CA2694951C - Insulating annular fluid - Google Patents
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- CA2694951C CA2694951C CA2694951A CA2694951A CA2694951C CA 2694951 C CA2694951 C CA 2694951C CA 2694951 A CA2694951 A CA 2694951A CA 2694951 A CA2694951 A CA 2694951A CA 2694951 C CA2694951 C CA 2694951C
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/82—Oil-based compositions
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Abstract
A method for emplacing a packer fluid into an annulus is described that includes preparing the packer fluid, where the packer fluid includes a hydrocarbon fluid, and a micronized weighting agent; and then pumping the packer fluid into the annulus.
A method of stimulating a well that includes injecting a gas into an annular fluid, where the fluid includes a hydrocarbon fluid, and a micronized weighting agent is also disclosed.
A method of stimulating a well that includes injecting a gas into an annular fluid, where the fluid includes a hydrocarbon fluid, and a micronized weighting agent is also disclosed.
Description
Insulating Annular Fluid Background of Invention Field of the Invention [00011 The invention relates generally to viscosifiable, low thermal conductivity annular fluids and methods of viscosifying, emplacing, and removing the fluids.
Background Art [00021 Annular fluids or packer fluids are liquids which are pumped into annular openings such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus in a wellbore comprising at least an A- and B-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string, or (4) in one or more of an A-, B- or C-annulus in a wellbore comprising at least an A-, B- and C-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string.
[0003] Yet alternatively, said one or more strings of pipe may simply run through a conduit or outer pipe(s) to connect one or more wellbores to another wellbore or to lead from one or more wellb ores to a centralized gathering or processing center; and said annular fluid may have been emplaced within said conduit or pipe(s) but external to said one or more strings of pipe therein. Insulating annular fluids or insulating packer fluids are annular fluids or packer fluids used to control heat loss ¨
both conductive and convective heat losses. These insulating annular or packer fluids are especially necessary in oil or gas well construction operations conducted in low temperature venues of the world, for example, those areas having permafrost [0004] Permafrost is a thick layer of frozen surface ground found often in arctic or antarctic regions, which frozen ground may be several hundred feet thick and presents a great obstacle to the removal of relatively warm fluids through a well pipe penetrating said frozen ground. Particularly, warm fluid in the well pipe causes thawing of the permafrost in the vicinity of the well resulting in subsidence which can irreparably impair the permafrost environment and impose compressive and/or tension loads high enough to rupture or collapse the well casing and hence allow the escape of well fluids. In addition, the warm gas or oil coming to the surface in the well pipe becomes cooled by giving up its heat to the permafrost. Further, gas hydrate crystals .may form, which can freeze together and block the well pipe;
alternatively, wax or asphaltenes may form, which can agglomerate and block the well pipe. Generally, except for a tiny contribution from radiation, annular heat loss is due to convection and to conduction.
[0005] Heavy oil production is another operation which often can benefit from the use of an insulating annular fluid. In heavy oil production, a high-pressure steam or hot water is injected into the well and the oil reservoir to heat the fluids in the reservoir, causing a thennal expansion of the crude oil, an increase in reservoir pressure and a decrease of the oil's viscosity. In this process, damage to the well casing may occur when heat is transferred through the annulus between the well tubing and the casing.
The resulting thermal expansion of the casing can break the bond between the casing and the surrounding cement, causing leakage. Accordingly, an insulating medium such as a packer fluid may be used to insulate or to help insulate the well tubing.
The packer fluid also reduces heat loss and saves on the energy requirements in stimulation using hot-water or steam (huff-n-puff) or in hot-water- or steam-flooding.
[0006] In addition to steam injection processes and operations which require production through a peiniafrost layer, subsea fields ¨ especially, subsea fields in deep water, 1,500 to more than 6,000 feet deep ¨ require specially designed systems, which typically require an insulating annular or packer fluid. For example, a subsea oil reservoir temperature may be between about 120 F and 250 F, while the temperature of the water through which the oil must be conveyed is often as low as 32 F to 50 F. Conveying the high temperature oil through such a low temperature environment can result in oil temperature reduction and consequently the separation of the oils into various hydrocarbon fractions and the deposition of paraffins, waxes,
Background Art [00021 Annular fluids or packer fluids are liquids which are pumped into annular openings such as, for example, (1) between a wellbore wall and one or more casing strings of pipe extending into a wellbore, or (2) between adjacent, concentric strings of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus in a wellbore comprising at least an A- and B-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string, or (4) in one or more of an A-, B- or C-annulus in a wellbore comprising at least an A-, B- and C-annulus with one or more inner strings of pipe extending into a said wellbore, which may be running in parallel or nominally in parallel with each other and may or may not be concentric or nominally concentric with the outer casing string.
[0003] Yet alternatively, said one or more strings of pipe may simply run through a conduit or outer pipe(s) to connect one or more wellbores to another wellbore or to lead from one or more wellb ores to a centralized gathering or processing center; and said annular fluid may have been emplaced within said conduit or pipe(s) but external to said one or more strings of pipe therein. Insulating annular fluids or insulating packer fluids are annular fluids or packer fluids used to control heat loss ¨
both conductive and convective heat losses. These insulating annular or packer fluids are especially necessary in oil or gas well construction operations conducted in low temperature venues of the world, for example, those areas having permafrost [0004] Permafrost is a thick layer of frozen surface ground found often in arctic or antarctic regions, which frozen ground may be several hundred feet thick and presents a great obstacle to the removal of relatively warm fluids through a well pipe penetrating said frozen ground. Particularly, warm fluid in the well pipe causes thawing of the permafrost in the vicinity of the well resulting in subsidence which can irreparably impair the permafrost environment and impose compressive and/or tension loads high enough to rupture or collapse the well casing and hence allow the escape of well fluids. In addition, the warm gas or oil coming to the surface in the well pipe becomes cooled by giving up its heat to the permafrost. Further, gas hydrate crystals .may form, which can freeze together and block the well pipe;
alternatively, wax or asphaltenes may form, which can agglomerate and block the well pipe. Generally, except for a tiny contribution from radiation, annular heat loss is due to convection and to conduction.
[0005] Heavy oil production is another operation which often can benefit from the use of an insulating annular fluid. In heavy oil production, a high-pressure steam or hot water is injected into the well and the oil reservoir to heat the fluids in the reservoir, causing a thennal expansion of the crude oil, an increase in reservoir pressure and a decrease of the oil's viscosity. In this process, damage to the well casing may occur when heat is transferred through the annulus between the well tubing and the casing.
The resulting thermal expansion of the casing can break the bond between the casing and the surrounding cement, causing leakage. Accordingly, an insulating medium such as a packer fluid may be used to insulate or to help insulate the well tubing.
The packer fluid also reduces heat loss and saves on the energy requirements in stimulation using hot-water or steam (huff-n-puff) or in hot-water- or steam-flooding.
[0006] In addition to steam injection processes and operations which require production through a peiniafrost layer, subsea fields ¨ especially, subsea fields in deep water, 1,500 to more than 6,000 feet deep ¨ require specially designed systems, which typically require an insulating annular or packer fluid. For example, a subsea oil reservoir temperature may be between about 120 F and 250 F, while the temperature of the water through which the oil must be conveyed is often as low as 32 F to 50 F. Conveying the high temperature oil through such a low temperature environment can result in oil temperature reduction and consequently the separation of the oils into various hydrocarbon fractions and the deposition of paraffins, waxes,
2 asphaltenes, and gas hydrates. The agglomeration of these oil constituents can cause blocking or restriction of the wellbore, resulting in significant reduction or even catastrophic failure of the production operation.
[0007] To meet the above-discussed insulating demands, a variety of packer fluids have been developed. For example, U.S. Pat. No. 3,613,792 describes an early method of insulating wellbores. In the 3,613,792 patent, simple fluids and solids are used as the insulating medium. U.S. Pat. No. 4,258,791 improves on these insulating materials by disclosing an oleaginous liquid such as topped crude oils, gas oils, kerosene, diesel fluids, heavy alkylates, fractions of heavy alkylates and the like in combination with an aqueous phase, lime, and a polymeric material. U.S.
Pat.
No. 4,528,104 teaches a packer fluid comprised of an oleaginous liquid such as diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and the like in combination with an organophillic clay gellant and a clay dispersant such as a polar organic compound and a polyfunctional amino-silane.
[0008] Gelled hydrocarbons have been successfully used as packer fluids because the hydrocarbon fluids have low thermal conductivities, while gel formation increases the viscosities of the fluids. The increased viscosity minimizes fluid movement in packer fluids, leading to reduced or minimized convective heat loss.
[0009] Polyvalent metal (typically, ferric iron or aluminum) salts of phosphoric acid esters have been successfully used as gelling agents for forming high viscosity gelled hydrocarbon fluids. Description of these fluids and their uses can be found in U.S. Patent Nos. 4,507,213 issued to Daccord et al., 4,622,155 issued to Harris et al., 5,190,675 issued to Gross, and 5,846,915 issued to Smith et al. More recently, U.S. Patent No. 6,511,944 issued to Taylor et al. discloses gelled hydrocarbon fracture fluids that include ferric iron or aluminum polyvalent metal salts of phosphonic acid esters, instead of phosphoric acid esters.
[0010] Another short-coming of hydraulic fracturing fluids has been their limited stability ¨ after all, they need only last a matter of hours, since even a massive hydraulic fracturing job involving 2,000,000 pounds of proppant is typically concluded in less than 8 hours. Although these fluids have worked well in the hydraulic fracturing application, there is still a need for insulating annular or packer
[0007] To meet the above-discussed insulating demands, a variety of packer fluids have been developed. For example, U.S. Pat. No. 3,613,792 describes an early method of insulating wellbores. In the 3,613,792 patent, simple fluids and solids are used as the insulating medium. U.S. Pat. No. 4,258,791 improves on these insulating materials by disclosing an oleaginous liquid such as topped crude oils, gas oils, kerosene, diesel fluids, heavy alkylates, fractions of heavy alkylates and the like in combination with an aqueous phase, lime, and a polymeric material. U.S.
Pat.
No. 4,528,104 teaches a packer fluid comprised of an oleaginous liquid such as diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and the like in combination with an organophillic clay gellant and a clay dispersant such as a polar organic compound and a polyfunctional amino-silane.
[0008] Gelled hydrocarbons have been successfully used as packer fluids because the hydrocarbon fluids have low thermal conductivities, while gel formation increases the viscosities of the fluids. The increased viscosity minimizes fluid movement in packer fluids, leading to reduced or minimized convective heat loss.
[0009] Polyvalent metal (typically, ferric iron or aluminum) salts of phosphoric acid esters have been successfully used as gelling agents for forming high viscosity gelled hydrocarbon fluids. Description of these fluids and their uses can be found in U.S. Patent Nos. 4,507,213 issued to Daccord et al., 4,622,155 issued to Harris et al., 5,190,675 issued to Gross, and 5,846,915 issued to Smith et al. More recently, U.S. Patent No. 6,511,944 issued to Taylor et al. discloses gelled hydrocarbon fracture fluids that include ferric iron or aluminum polyvalent metal salts of phosphonic acid esters, instead of phosphoric acid esters.
[0010] Another short-coming of hydraulic fracturing fluids has been their limited stability ¨ after all, they need only last a matter of hours, since even a massive hydraulic fracturing job involving 2,000,000 pounds of proppant is typically concluded in less than 8 hours. Although these fluids have worked well in the hydraulic fracturing application, there is still a need for insulating annular or packer
3 , fluids that are stable for extended periods, low in thermal conductivity, and simultaneously inhibitive of convective heat loss.
Summary of Invention [0011] In one aspect, the present disclosure relates to a method of preventing hydrate formation during oil production through a subsea field or permafrost layer, comprising:
preparing the packer fluid comprising: a hydrocarbon fluid, and a micronized weighting agent, wherein the micronized weighting agent has a particle size d90 of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%;
pumping the packer fluid into an annulus; and producing an oil from a formation through a pipe extending through the packer fluid.
[0012] In another aspect, the present disclosure relates to a method for stimulating a well, comprising preparing the packer fluid comprising: a hydrocarbon fluid, and a coated micronized weighting agent, wherein the micronized weighting agent has a particle size d90 of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%; pumping the packer fluid into an annulus; and injecting hot-water or steam through a pipe extending through the packer fluid.
[0013] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
Summary of Invention [0011] In one aspect, the present disclosure relates to a method of preventing hydrate formation during oil production through a subsea field or permafrost layer, comprising:
preparing the packer fluid comprising: a hydrocarbon fluid, and a micronized weighting agent, wherein the micronized weighting agent has a particle size d90 of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%;
pumping the packer fluid into an annulus; and producing an oil from a formation through a pipe extending through the packer fluid.
[0012] In another aspect, the present disclosure relates to a method for stimulating a well, comprising preparing the packer fluid comprising: a hydrocarbon fluid, and a coated micronized weighting agent, wherein the micronized weighting agent has a particle size d90 of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%; pumping the packer fluid into an annulus; and injecting hot-water or steam through a pipe extending through the packer fluid.
[0013] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
4 Detailed Description [0014] Embodiments of the present disclosure relate to insulating packer fluids and methods of preparing and emplacing such fluids. Packer fluids according to the present disclosure have good long-term insulation properties, because they resist syneresis and separation of various components into separate phases, and have low thermal conductivities and unique rheological properties that minimize their movement once they are emplaced - and this minimization of movement, in turn, minimizes convective heat loss.
[0015] A majority of annular heat loss is due to convection and conduction.
Heat loss due to thermal conductivity may be controlled by proper selection of fluids, i.e., fluids with low thermal conductivities, while heat loss due to convection can be arrested or substantially diminished by increased viscosities of the fluids.
For example, thermal conductivities as low as 0.07 btu/(hr=ft. F) can be obtained with gelled diesel or other hydrocarbon-based insulating annular fluid.
[0016] In certain aspects, disclosed embodiments relate to insulating packer fluids, and methods of emplacing and subsequently removing such fluids. Packer fluids according to embodiments disclosed herein may have relatively high densities, and may be adapted to survive in high temperature and/or high pressure wells.
[0017] More specifically, insulating packer fluids in accordance with disclosed embodiments comprise oil-based (hydrocarbon-based) fluids, comprising micronized weighting agents, because oil-based fluids typically have very low thermal conductivities. For example, thermal conductivities as low as 0.07 btu/(hr=ft.
F) can be obtained with gelled diesel or other hydrocarbon-based insulating annular fluids.
[0015] A majority of annular heat loss is due to convection and conduction.
Heat loss due to thermal conductivity may be controlled by proper selection of fluids, i.e., fluids with low thermal conductivities, while heat loss due to convection can be arrested or substantially diminished by increased viscosities of the fluids.
For example, thermal conductivities as low as 0.07 btu/(hr=ft. F) can be obtained with gelled diesel or other hydrocarbon-based insulating annular fluid.
[0016] In certain aspects, disclosed embodiments relate to insulating packer fluids, and methods of emplacing and subsequently removing such fluids. Packer fluids according to embodiments disclosed herein may have relatively high densities, and may be adapted to survive in high temperature and/or high pressure wells.
[0017] More specifically, insulating packer fluids in accordance with disclosed embodiments comprise oil-based (hydrocarbon-based) fluids, comprising micronized weighting agents, because oil-based fluids typically have very low thermal conductivities. For example, thermal conductivities as low as 0.07 btu/(hr=ft.
F) can be obtained with gelled diesel or other hydrocarbon-based insulating annular fluids.
5 [0018] Micronized Weighting Agent [0019] Fluids used in embodiments disclosed herein may include micronized weighting agents. In some embodiments, the micronized weighting agents may be uncoated. In other embodiments, the micronized weighting agents may be coated with a dispersant. For example, fluids used in some embodiments disclosed herein may include dispersant coated micronized weighting agents. The coated weighting agents may be formed by either a dry coating process or a wet coating process.
Weighting agents suitable for use in other embodiments disclosed herein may include those disclosed in U.S. Patent Application Publication Nos.
20040127366, 20050101493, 20060188651, U.S. Patent Nos. 6,586,372; 7,176,165; and 7,918,289.
[0020] ]Micronized weighting agents used in some embodiments disclosed herein may include a variety of compounds well known to one of skill in the art. In a particular embodiment, the weighting agent may be selected from one or more of the materials including, for example, barium sulphate (barite), calcium carbonate (calcite), dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese oxide, and strontium sulphate. One having ordinary skill in the art would recognize that selection of a particular material may depend largely on the density of the material as typically, the lowest wellbore fluid viscosity at any particular density is obtained by using the highest density particles. However, other considerations may influence the choice of product such as cost, local availability, the power required for grinding, and whether the residual solids or filter cake may be readily removed from the well.
5a 100211 In one embodiment, the micronized weighting agent may have a d90 ranging from 1 to 25 microns and a d50 ranging from 0.5 to 10 microns. In another embodiment, the micronized weighting agent includes particles having a d90 ranging from 2 to 8 microns and a d50 ranging from 0.5 to 5 microns. One of ordinary skill in the art would recognize that, depending on the sizing technique, the weighting agent may have a particle size distribution other than a monomodal distribution.
That is, the weighting agent may have a particle size distribution that, in various embodiments, may be rnonomodal, which may or may not be Gaussian, bimodal, or polymodal.
[0022] It has been found that a predominance of particles that are too fine (i.e. below about 1 micron) results in the formation of a high rheology paste. Thus, it has been unexpectedly found that the weighting agent particles must be sufficiently small to avoid issues of sag, but not so small as to have an adverse impact on rheology. Thus weighting agent (barite) particles meeting the particle size distribution criteria disclosed herein may be used without adversely impacting the 'theological properties of the wellbore fluids.
[0023] In one embodiment, a micronized weighting agent is sized such that: particles having a diameter less than 1 microns are 0 to 15 percent by volume; particles having a diameter between 1 microns and 4 microns are 15 to 40 percent by volume;
particles having a diameter between 4 microns and 8 microns are 15 to 30 by volume; particles having a diameter between 8 microns and 12 microns are 5 to percent by volume; particles having a diameter between 12 microns and 16 microns are 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns are 0 to 10 percent by volume; particles having a diameter greater than 20 microns are 0 to 5 percent by volume. In another embodiment, the micronized weighting agent is sized so that the cumulative volume distribution is: less than 10 percent or the particles are less than 1 microns; less than 25 percent are in the range of 1 microns to 3 microns; less than 50 percent are in the range of 2 microns to 6 microns; less than 75 percent are in the range of 6 microns to 10 microns; and less than 90 percent are in the range of 10 microns to 24 microns.
[0024] The use of micronized weighting agents has been disclosed in U.S. Patent Application Publication No. 20050277553 assigned to the assignee of the current
Weighting agents suitable for use in other embodiments disclosed herein may include those disclosed in U.S. Patent Application Publication Nos.
20040127366, 20050101493, 20060188651, U.S. Patent Nos. 6,586,372; 7,176,165; and 7,918,289.
[0020] ]Micronized weighting agents used in some embodiments disclosed herein may include a variety of compounds well known to one of skill in the art. In a particular embodiment, the weighting agent may be selected from one or more of the materials including, for example, barium sulphate (barite), calcium carbonate (calcite), dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese oxide, and strontium sulphate. One having ordinary skill in the art would recognize that selection of a particular material may depend largely on the density of the material as typically, the lowest wellbore fluid viscosity at any particular density is obtained by using the highest density particles. However, other considerations may influence the choice of product such as cost, local availability, the power required for grinding, and whether the residual solids or filter cake may be readily removed from the well.
5a 100211 In one embodiment, the micronized weighting agent may have a d90 ranging from 1 to 25 microns and a d50 ranging from 0.5 to 10 microns. In another embodiment, the micronized weighting agent includes particles having a d90 ranging from 2 to 8 microns and a d50 ranging from 0.5 to 5 microns. One of ordinary skill in the art would recognize that, depending on the sizing technique, the weighting agent may have a particle size distribution other than a monomodal distribution.
That is, the weighting agent may have a particle size distribution that, in various embodiments, may be rnonomodal, which may or may not be Gaussian, bimodal, or polymodal.
[0022] It has been found that a predominance of particles that are too fine (i.e. below about 1 micron) results in the formation of a high rheology paste. Thus, it has been unexpectedly found that the weighting agent particles must be sufficiently small to avoid issues of sag, but not so small as to have an adverse impact on rheology. Thus weighting agent (barite) particles meeting the particle size distribution criteria disclosed herein may be used without adversely impacting the 'theological properties of the wellbore fluids.
[0023] In one embodiment, a micronized weighting agent is sized such that: particles having a diameter less than 1 microns are 0 to 15 percent by volume; particles having a diameter between 1 microns and 4 microns are 15 to 40 percent by volume;
particles having a diameter between 4 microns and 8 microns are 15 to 30 by volume; particles having a diameter between 8 microns and 12 microns are 5 to percent by volume; particles having a diameter between 12 microns and 16 microns are 3 to 7 percent by volume; particles having a diameter between 16 microns and 20 microns are 0 to 10 percent by volume; particles having a diameter greater than 20 microns are 0 to 5 percent by volume. In another embodiment, the micronized weighting agent is sized so that the cumulative volume distribution is: less than 10 percent or the particles are less than 1 microns; less than 25 percent are in the range of 1 microns to 3 microns; less than 50 percent are in the range of 2 microns to 6 microns; less than 75 percent are in the range of 6 microns to 10 microns; and less than 90 percent are in the range of 10 microns to 24 microns.
[0024] The use of micronized weighting agents has been disclosed in U.S. Patent Application Publication No. 20050277553 assigned to the assignee of the current
6 application.
Particles having these size distributions may be obtained by several means. For example, sized particles, such as a suitable barite product having similar particle size distributions as disclosed herein, may be commercially purchased. A coarser ground suitable material may be obtained, and the material may be further ground by any known technique to the desired particle size. Such techniques include jet-milling, ball milling, high performance wet and dry milling techniques, or any other technique that is known in the art generally for milling powdered products.
[0025] In one embodiment, appropriately sized particles of barite may be selectively removed from a product stream of a conventional barite grinding plant, which may include selectively removing the fines from a conventional API-grade barite grinding operation. Fines are often considered a by-product of the grinding process, and conventionally these materials are blended with courser materials to achieve API-grade barite. However, in accordance with the present disclosure, these by-product fines may be further processed via an air classifier to achieve the particle size distributions disclosed herein. In yet another embodiment, the micronized weighting agents may be formed by chemical precipitation. Such precipitated products may be used alone or in combination with mechanically milled products.
[0026] In some embodiments, the micronized weighting agents include solid colloidal particles having a deflocculating agent or dispersant coated onto the surface of the particle. Further, one of ordinary skill would appreciate that the term "colloidal"
refers to a suspension of the particles, and does not impart any specific size limitation. Rather, the size of the micronized weighting agents of the present disclosure may vary in range and are only limited by the claims of the present application. The micronized particle size generates high density suspensions or slurries that show a reduced tendency to sediment or sag, while the dispersant on the surface of the particle controls the inter-particle interactions resulting in lower rheological profiles. Thus, the combination of high density, fine particle size, and control of colloidal interactions by surface coating the particles with a dispersant reconciles the objectives of high density, lower viscosity and minimal sag.
[0027] In some embodiments, a dispersant may be coated onto the particulate weighting additive during the comminution (grinding) process. That is to say,
Particles having these size distributions may be obtained by several means. For example, sized particles, such as a suitable barite product having similar particle size distributions as disclosed herein, may be commercially purchased. A coarser ground suitable material may be obtained, and the material may be further ground by any known technique to the desired particle size. Such techniques include jet-milling, ball milling, high performance wet and dry milling techniques, or any other technique that is known in the art generally for milling powdered products.
[0025] In one embodiment, appropriately sized particles of barite may be selectively removed from a product stream of a conventional barite grinding plant, which may include selectively removing the fines from a conventional API-grade barite grinding operation. Fines are often considered a by-product of the grinding process, and conventionally these materials are blended with courser materials to achieve API-grade barite. However, in accordance with the present disclosure, these by-product fines may be further processed via an air classifier to achieve the particle size distributions disclosed herein. In yet another embodiment, the micronized weighting agents may be formed by chemical precipitation. Such precipitated products may be used alone or in combination with mechanically milled products.
[0026] In some embodiments, the micronized weighting agents include solid colloidal particles having a deflocculating agent or dispersant coated onto the surface of the particle. Further, one of ordinary skill would appreciate that the term "colloidal"
refers to a suspension of the particles, and does not impart any specific size limitation. Rather, the size of the micronized weighting agents of the present disclosure may vary in range and are only limited by the claims of the present application. The micronized particle size generates high density suspensions or slurries that show a reduced tendency to sediment or sag, while the dispersant on the surface of the particle controls the inter-particle interactions resulting in lower rheological profiles. Thus, the combination of high density, fine particle size, and control of colloidal interactions by surface coating the particles with a dispersant reconciles the objectives of high density, lower viscosity and minimal sag.
[0027] In some embodiments, a dispersant may be coated onto the particulate weighting additive during the comminution (grinding) process. That is to say,
7 coarse weighting additive is ground in the presence of a relatively high concentration of dispersant such that the newly formed surfaces of the fine particles are exposed to and thus coated by the dispersant. It is speculated that this allows the dispersant to find an acceptable conformation on the particle surface thus coating the surface. Alternatively, it is speculated that because a relatively higher concentration of dispersant is in the grinding fluid, as opposed to that in a drilling fluid, the dispersant is more likely to be absorbed (either physically or chemically) to the particle surface.
[0028] As that term is used in herein, "coating of the surface" is intended to mean that a sufficient number of dispersant molecules are absorbed (physically or chemically) or otherwise closely associated with the surface of the particles so that the fine particles of material do not cause the rapid rise in viscosity observed in the prior art.
By using such a definition, one of skill in the art should understand and appreciate that the dispersant molecules may not actually be fully covering the particle surface and that quantification of the number of molecules is very difficult.
[0029] Therefore, by necessity, reliance is made on a results oriented definition. As a result of the process, one can control the colloidal interactions of the fine particles by coating the particle with dispersants prior to addition to the drilling fluid. By doing so, it is possible to systematically control the rheological properties of fluids containing in the additive as well as the tolerance to contaminants in the fluid in addition to enhancing the fluid loss (filtration) properties of the fluid.
[0030] In some embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d50) of less than 10 microns that are coated with a polymeric deflocculating agent or dispersing agent. In other embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d50) of less than 8 microns that are coated with a polymeric deflocculating agent or dispersing agent; less than 6 microns in other embodiments; less than 4 microns in other embodiments; and less than 2 microns in yet other embodiments.
[0031] The fine particle size will generate suspensions or slurries that will show a reduced tendency to sediment or sag, and the polymeric dispersing agent on the surface of the particle may control the inter-particle interactions and thus will
[0028] As that term is used in herein, "coating of the surface" is intended to mean that a sufficient number of dispersant molecules are absorbed (physically or chemically) or otherwise closely associated with the surface of the particles so that the fine particles of material do not cause the rapid rise in viscosity observed in the prior art.
By using such a definition, one of skill in the art should understand and appreciate that the dispersant molecules may not actually be fully covering the particle surface and that quantification of the number of molecules is very difficult.
[0029] Therefore, by necessity, reliance is made on a results oriented definition. As a result of the process, one can control the colloidal interactions of the fine particles by coating the particle with dispersants prior to addition to the drilling fluid. By doing so, it is possible to systematically control the rheological properties of fluids containing in the additive as well as the tolerance to contaminants in the fluid in addition to enhancing the fluid loss (filtration) properties of the fluid.
[0030] In some embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d50) of less than 10 microns that are coated with a polymeric deflocculating agent or dispersing agent. In other embodiments, the weighting agents include dispersed solid colloidal particles with a weight average particle diameter (d50) of less than 8 microns that are coated with a polymeric deflocculating agent or dispersing agent; less than 6 microns in other embodiments; less than 4 microns in other embodiments; and less than 2 microns in yet other embodiments.
[0031] The fine particle size will generate suspensions or slurries that will show a reduced tendency to sediment or sag, and the polymeric dispersing agent on the surface of the particle may control the inter-particle interactions and thus will
8 produce lower rheological profiles. It is the combination of fine particle size and control of colloidal interactions that reconciles the two objectives of lower viscosity and minimal sag. Additionally, the presence of the dispersant in the comminution process yields discrete particles which can form a more efficiently packed filter cake and so advantageously reduce filtration rates.
10032] Coating of the micronized weighting agent with the dispersant may also be performed in a dry blending process such that the process is substantially free of solvent. The process includes blending the weighting agent and a dispersant at a desired ratio to form a blended material. In one embodiment, the weighting agent may be un-sized initially and rely on the blending process to grind the particles into the desired size range as disclosed above. Alternatively, the process may begin with sized weighting agents. The blended material may then be fed to a heat exchange system, such as a thermal desorption system.
[0033] The mixture may be forwarded through the heat exchanger using a mixer, such as a screw conveyor. Upon cooling, the polymer may remain associated with the weighting agent. The polymer/weighting agent mixture may then be separated into polymer coated weighting agent, unassociated polymer, and any agglomerates that may have formed. The unassociated polymer may optionally be recycled to the beginning of the process, if desired. In another embodiment, the dry blending process alone may serve to coat the weighting agent without heating.
[0034] Alternatively, a sized weighting agent may be coated by thermal adsorption as described above, in the absence of a dry blending process. In this embodiment, a process for making a coated substrate may include heating a sized weighting agent to a temperature sufficient to react monomeric dispersant onto the weighting agent to form a polymer coated sized weighting agent and recovering the polymer coated weighting agent. In another embodiment, one may use a catalyzed process to form the polymer in the presence of the sized weighting agent. In yet another embodiment, the polymer may be preformed and may be thermally adsorbed onto the sized weighting agent.
[0035] In some embodiments, the micronized weighting agent may be formed of particles that are composed of a material of specific gravity of at least 2.3;
at least 2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in other
10032] Coating of the micronized weighting agent with the dispersant may also be performed in a dry blending process such that the process is substantially free of solvent. The process includes blending the weighting agent and a dispersant at a desired ratio to form a blended material. In one embodiment, the weighting agent may be un-sized initially and rely on the blending process to grind the particles into the desired size range as disclosed above. Alternatively, the process may begin with sized weighting agents. The blended material may then be fed to a heat exchange system, such as a thermal desorption system.
[0033] The mixture may be forwarded through the heat exchanger using a mixer, such as a screw conveyor. Upon cooling, the polymer may remain associated with the weighting agent. The polymer/weighting agent mixture may then be separated into polymer coated weighting agent, unassociated polymer, and any agglomerates that may have formed. The unassociated polymer may optionally be recycled to the beginning of the process, if desired. In another embodiment, the dry blending process alone may serve to coat the weighting agent without heating.
[0034] Alternatively, a sized weighting agent may be coated by thermal adsorption as described above, in the absence of a dry blending process. In this embodiment, a process for making a coated substrate may include heating a sized weighting agent to a temperature sufficient to react monomeric dispersant onto the weighting agent to form a polymer coated sized weighting agent and recovering the polymer coated weighting agent. In another embodiment, one may use a catalyzed process to form the polymer in the presence of the sized weighting agent. In yet another embodiment, the polymer may be preformed and may be thermally adsorbed onto the sized weighting agent.
[0035] In some embodiments, the micronized weighting agent may be formed of particles that are composed of a material of specific gravity of at least 2.3;
at least 2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in other
9 embodiments; and at least 2.68 in yet other embodiments. For example, a weighting agent formed of particles having a specific gravity of at least 2.68 may allow wellbore fluids to be formulated to meet most density requirements yet have a particulate volume fraction low enough for the fluid to be pumpable.
[0036] As mentioned above, embodiments of the micronized weighting agent may include a deflocculating agent or a dispersant. In one embodiment, the dispersant may be selected from carboxylic acids of molecular weight of at least 150 Daltons, such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acids, phospholipids such as lecithin, including salts thereof and including mixtures thereof. Synthetic polymers may also be used, such as HYPERMER 0M-1 (Imperial Chemical Industries, PLC, London, United Kingdom) or polyacrylate esters, for example. Such polyacrylate esters may include polymers of stearyl methacrylate and/or butylacrylate. In another embodiment, the corresponding acids methacrylic acid and/or acrylic acid may be used. One skilled in the art would recognize that other acrylate or other unsaturated carboxylic acid monomers (or esters thereof) may be used to achieve substantially the same results as disclosed herein.
[0037] The polymeric dispersant may have an average molecular weight from about
[0036] As mentioned above, embodiments of the micronized weighting agent may include a deflocculating agent or a dispersant. In one embodiment, the dispersant may be selected from carboxylic acids of molecular weight of at least 150 Daltons, such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acids, phospholipids such as lecithin, including salts thereof and including mixtures thereof. Synthetic polymers may also be used, such as HYPERMER 0M-1 (Imperial Chemical Industries, PLC, London, United Kingdom) or polyacrylate esters, for example. Such polyacrylate esters may include polymers of stearyl methacrylate and/or butylacrylate. In another embodiment, the corresponding acids methacrylic acid and/or acrylic acid may be used. One skilled in the art would recognize that other acrylate or other unsaturated carboxylic acid monomers (or esters thereof) may be used to achieve substantially the same results as disclosed herein.
[0037] The polymeric dispersant may have an average molecular weight from about
10,000 Daltons to about 300,000 Daltons in one embodiment, from about 17,000 Daltons to about 40,000 Daltons in another embodiment, and from about 200,000-300,000 Daltons in yet another embodiment. One of ordinary skill in the art would recognize that when the dispersant is added to the weighting agent during a grinding process, intermediate molecular weight polymers (10,000-300,000 Daltons) may be used.
[0038]
Further, it is specifically within the scope of the embodiments disclosed herein that the polymeric dispersant be polymerized prior to or simultaneously with the wet or dry blending processes disclosed herein. Such polymerizations may involve, for example, thermal polymerization, catalyzed polymerization, initiated polymerization or combinations thereof.
Given the particulate nature of the micronized and dispersant coated micronized weighting agents disclosed herein, one of skill in the art should appreciate that additional components may be mixed with the weighting agent to modify various macroscopic properties. For example, anti-caking agents, lubricating agents, and agents used to mitigate moisture build-up may be included.
Alternatively, solid materials that enhance lubricity or help control fluid loss may be added to the weighting agents and drilling fluid disclosed herein. In one illustrative example, finely powdered natural graphite, petroleum coke, graphitized carbon, or mixtures of these are added to enhance lubricity, rate of penetration, and fluid loss as well as other properties of the drilling fluid.
Another illustrative embodiment utilizes finely ground polymer materials to impart various characteristics to the drilling fluid. In instances where such materials are added, it is important to note that the volume of added material should not have a substantial adverse impact on the properties and performance of the drilling fluids.
In one illustrative embodiment, polymeric fluid loss materials comprising less than 5 percent by weight are added to enhance the properties of the drilling fluid.
Alternatively, less than 5 percent by weight of suitably sized graphite and petroleum coke are added to enhance the lubricity and fluid loss properties of the fluid.
Finally, in another illustrative embodiment, less than 5 percent by weight of a conventional anti-caking agent is added to assist in the bulk storage of the weighting materials.
[00411 The particulate materials as described herein (i.e., the coated and/or uncoated micronized weighting agents) may be added to a drilling fluid as a weighting agent in a dry form or concentrated as slurry in an organic liquid. As is known, an organic liquid should have the necessary environmental characteristics required for additives to oil-based drilling fluids. With this in mind, the oleaginous fluid may have a kinematic viscosity of less than 10 centistokes (10 mm2/s) at 40 C and, for safety reasons, a flash point of greater than 60 C. Suitable oleaginous liquids are, for example, diesel oil, mineral or white oils, n-alkanes or synthetic oils such as alpha-olefin oils, ester oils, mixtures of these fluids, as well as other similar fluids known to one of skill in the art of drilling or other wellbore fluid formulation. In one embodiment, the desired particle size distribution is achieved via wet milling of the courser materials in the desired carrier fluid.
[0038]
Further, it is specifically within the scope of the embodiments disclosed herein that the polymeric dispersant be polymerized prior to or simultaneously with the wet or dry blending processes disclosed herein. Such polymerizations may involve, for example, thermal polymerization, catalyzed polymerization, initiated polymerization or combinations thereof.
Given the particulate nature of the micronized and dispersant coated micronized weighting agents disclosed herein, one of skill in the art should appreciate that additional components may be mixed with the weighting agent to modify various macroscopic properties. For example, anti-caking agents, lubricating agents, and agents used to mitigate moisture build-up may be included.
Alternatively, solid materials that enhance lubricity or help control fluid loss may be added to the weighting agents and drilling fluid disclosed herein. In one illustrative example, finely powdered natural graphite, petroleum coke, graphitized carbon, or mixtures of these are added to enhance lubricity, rate of penetration, and fluid loss as well as other properties of the drilling fluid.
Another illustrative embodiment utilizes finely ground polymer materials to impart various characteristics to the drilling fluid. In instances where such materials are added, it is important to note that the volume of added material should not have a substantial adverse impact on the properties and performance of the drilling fluids.
In one illustrative embodiment, polymeric fluid loss materials comprising less than 5 percent by weight are added to enhance the properties of the drilling fluid.
Alternatively, less than 5 percent by weight of suitably sized graphite and petroleum coke are added to enhance the lubricity and fluid loss properties of the fluid.
Finally, in another illustrative embodiment, less than 5 percent by weight of a conventional anti-caking agent is added to assist in the bulk storage of the weighting materials.
[00411 The particulate materials as described herein (i.e., the coated and/or uncoated micronized weighting agents) may be added to a drilling fluid as a weighting agent in a dry form or concentrated as slurry in an organic liquid. As is known, an organic liquid should have the necessary environmental characteristics required for additives to oil-based drilling fluids. With this in mind, the oleaginous fluid may have a kinematic viscosity of less than 10 centistokes (10 mm2/s) at 40 C and, for safety reasons, a flash point of greater than 60 C. Suitable oleaginous liquids are, for example, diesel oil, mineral or white oils, n-alkanes or synthetic oils such as alpha-olefin oils, ester oils, mixtures of these fluids, as well as other similar fluids known to one of skill in the art of drilling or other wellbore fluid formulation. In one embodiment, the desired particle size distribution is achieved via wet milling of the courser materials in the desired carrier fluid.
11 100421 Wellbore Fluid Formulation [0043] The sized particles described above (i.e., the micronized weighting agents (coated or uncoated) are combined in an oleaginous fluid (oil-based) wellbore fluid, as outlined below, along with other additives to create insulating packer fluids in accordance with described embodiments.
[00441 The oleaginous fluid may be a liquid, more preferably a natural or synthetic oil, and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof.
[0045] Conventional methods can be used to prepare the drilling fluids disclosed herein in a manner analogous to those normally used, to prepare oil-based drilling fluids. In one embodiment, a desired quantity of oleaginous fluid such as a base oil, and a suitable amount of one or more micronized weighting agents are mixed together and any remaining components are added sequentially with continuous mixing.
[0046] By formulating annular fluids in this manner, the present inventors have discovered that annular packer fluids may be formulated having densities up to about 20 ppg. Through the addition of other weighting agents, such as Fe03, it is possible to raise the density beyond this point. Typical prior art annular fluids, have significantly lower densities, such as about 8 ppg.
[0047] Other additives that may be included in the wellbore fluids disclosed herein include, for example, gelling agents, wetting agents, organophilic clays, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, rheological additives and cleaning agents. The addition of such agents should be well known to one of ordinary skill in the art of formulating drilling fluids and muds.
10048] One issue in formulating annular fluids is that oil phase separation can occur.
This phenomenon is known as "top oil loss" or "top oil separation", and can be
[00441 The oleaginous fluid may be a liquid, more preferably a natural or synthetic oil, and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof.
[0045] Conventional methods can be used to prepare the drilling fluids disclosed herein in a manner analogous to those normally used, to prepare oil-based drilling fluids. In one embodiment, a desired quantity of oleaginous fluid such as a base oil, and a suitable amount of one or more micronized weighting agents are mixed together and any remaining components are added sequentially with continuous mixing.
[0046] By formulating annular fluids in this manner, the present inventors have discovered that annular packer fluids may be formulated having densities up to about 20 ppg. Through the addition of other weighting agents, such as Fe03, it is possible to raise the density beyond this point. Typical prior art annular fluids, have significantly lower densities, such as about 8 ppg.
[0047] Other additives that may be included in the wellbore fluids disclosed herein include, for example, gelling agents, wetting agents, organophilic clays, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, rheological additives and cleaning agents. The addition of such agents should be well known to one of ordinary skill in the art of formulating drilling fluids and muds.
10048] One issue in formulating annular fluids is that oil phase separation can occur.
This phenomenon is known as "top oil loss" or "top oil separation", and can be
12 combated through the use of gelling agents. Specifically, by mixing gelling agents in with the base fluid and micronized weighting agent, the oil, which would otherwise phase separate, can be gelled, preventing this phenomenon.
Typically, gelling agents may be added in an amount of 0.1% by weight up to about 5% by weight or preferably 0.5% by weight up to about 3.5% by weight or more preferably 1% by weight up to about 2% by weight.
[0049] Gelling Agent [0050] In accordance with some embodiments of the present disclosure, a packer fluid comprises a theological additive, as noted above, added to a hydrocarbon fluid that includes one or more gelling agents, such as phosphoric acid esters in the presence of a ferric or aluminum compound. The hydrocarbons, for example, may be diesels, paraffin oils, crude oils, kerosene, or mixtures thereof. The phosphoric acid esters may have same or different alkyl groups, having various lengths. In accordance with embodiments of the invention, the alkyl groups (i.e., the ester parts) of the phosphoric acid esters have two or more carbon atoms, and preferably at least one of the alkyl groups has 3 to 10 carbon atoms. The ferric or aluminum compounds may be organic or inorganic compounds, such as aluminum chloride, aluminum alkoxide, ferric chloride, organometallic complexes of aluminum or iron(III), amine carboxylic acid salts of aluminum or iron(III), etc.
[0051] The phosphoric acid esters having a desired alkyl group may be prepared using phosphorous pentaoxide and triethyl phosphate (TEP) (or other similar phosphate triesters) in the presence of a trace amount of water:
Trace H20 P205 TEP 13205 + (Et0)2P(0)0H + TEP
50 "C
(Et0)2P(0)0H + ROH (R0)2P(0)0-H + Et0H
[0052] In the reactions shown above, the tri-ethyl phosphate ester (TEP) is partially hydrolyzed to produce a phosphoric acid diethyl ester. The phosphoric acid diethyl ester is then transesterified with a selected alcohol (ROH) to regenerate a phosphoric acid dialkyl ester having at least one and often two ester alkyl groups derived from the ROH.
[0053] The alcohol (ROH), i.e., the length of the alkyl chain R, may be selected to provide the desired hydrophobicity. In accordance with embodiments of the
Typically, gelling agents may be added in an amount of 0.1% by weight up to about 5% by weight or preferably 0.5% by weight up to about 3.5% by weight or more preferably 1% by weight up to about 2% by weight.
[0049] Gelling Agent [0050] In accordance with some embodiments of the present disclosure, a packer fluid comprises a theological additive, as noted above, added to a hydrocarbon fluid that includes one or more gelling agents, such as phosphoric acid esters in the presence of a ferric or aluminum compound. The hydrocarbons, for example, may be diesels, paraffin oils, crude oils, kerosene, or mixtures thereof. The phosphoric acid esters may have same or different alkyl groups, having various lengths. In accordance with embodiments of the invention, the alkyl groups (i.e., the ester parts) of the phosphoric acid esters have two or more carbon atoms, and preferably at least one of the alkyl groups has 3 to 10 carbon atoms. The ferric or aluminum compounds may be organic or inorganic compounds, such as aluminum chloride, aluminum alkoxide, ferric chloride, organometallic complexes of aluminum or iron(III), amine carboxylic acid salts of aluminum or iron(III), etc.
[0051] The phosphoric acid esters having a desired alkyl group may be prepared using phosphorous pentaoxide and triethyl phosphate (TEP) (or other similar phosphate triesters) in the presence of a trace amount of water:
Trace H20 P205 TEP 13205 + (Et0)2P(0)0H + TEP
50 "C
(Et0)2P(0)0H + ROH (R0)2P(0)0-H + Et0H
[0052] In the reactions shown above, the tri-ethyl phosphate ester (TEP) is partially hydrolyzed to produce a phosphoric acid diethyl ester. The phosphoric acid diethyl ester is then transesterified with a selected alcohol (ROH) to regenerate a phosphoric acid dialkyl ester having at least one and often two ester alkyl groups derived from the ROH.
[0053] The alcohol (ROH), i.e., the length of the alkyl chain R, may be selected to provide the desired hydrophobicity. In accordance with embodiments of the
13 invention, the alcohols (ROH) have 2 or more carbons (i.e., ethanol or higher), and preferably, 2 to 10 carbons, which may be straight or branched chains. The phosphoric acid dialkyl esters having the alkyl chain of 2-10 carbons long may be obtained from M-I L.L.C. (Houston, TX) under the trade name of ECF-976. In accordance with some embodiments of the invention, the R group may include aromatic or other functional groups, as long as it can still provide proper solubility in the hydrocarbon base fluids.
[0054] One of ordinary skill in the art would appreciate that various other reactions may be used to prepare the desired phosphoric esters without departing from the scope of the invention. For example, phosphoric acid esters may be prepared using phosphorous hemipentaoxide (or phosphorous pentaoxide P205) and a mixture of long chain alcohols, as disclosed in U.S. Patent No. 4,507,213:
P4010 + 3 ROH + 3 ROH->R0-P-OH +
OH
R0-P-OH + 2 RD-P-OR
[0055] This reaction produces a mixture of phosphoric acid mono esters and diesters.
Furthermore, while the above reaction is shown with two different alcohols, the same reaction may also be perfumed with one kind of alcohol to simplify the product composition. Note that embodiments of the invention may use a mixture of phosphoric acid esters, i.e., not limited to the use of a pure phosphoric acid ester. As used herein, "phosphoric acid esters" include mono acid di-esters and di-acid mono esters.
[0056] Furtheimore, instead of or in addition to phosphoric esters, embodiments disclosed herein may also use phosphonic acid esters, as disclosed in U.S.
Patent No. 6,511,944 issued to Taylor et al. A phosphonic acid ester has an alkyl group directly bonded to the phosphorous atom and includes one acid and one ester group.
One of ordinary skill in the art would also recognize that other types of gelling agents may be used including anionic polymers, such as poly-(ethylene-co-
[0054] One of ordinary skill in the art would appreciate that various other reactions may be used to prepare the desired phosphoric esters without departing from the scope of the invention. For example, phosphoric acid esters may be prepared using phosphorous hemipentaoxide (or phosphorous pentaoxide P205) and a mixture of long chain alcohols, as disclosed in U.S. Patent No. 4,507,213:
P4010 + 3 ROH + 3 ROH->R0-P-OH +
OH
R0-P-OH + 2 RD-P-OR
[0055] This reaction produces a mixture of phosphoric acid mono esters and diesters.
Furthermore, while the above reaction is shown with two different alcohols, the same reaction may also be perfumed with one kind of alcohol to simplify the product composition. Note that embodiments of the invention may use a mixture of phosphoric acid esters, i.e., not limited to the use of a pure phosphoric acid ester. As used herein, "phosphoric acid esters" include mono acid di-esters and di-acid mono esters.
[0056] Furtheimore, instead of or in addition to phosphoric esters, embodiments disclosed herein may also use phosphonic acid esters, as disclosed in U.S.
Patent No. 6,511,944 issued to Taylor et al. A phosphonic acid ester has an alkyl group directly bonded to the phosphorous atom and includes one acid and one ester group.
One of ordinary skill in the art would also recognize that other types of gelling agents may be used including anionic polymers, such as poly-(ethylene-co-
14 chloroethylene-co-[sodium chloroethylene-sulfonatep, or emulsions formed from an emulsifier and a water-miscible internal phase.
[0057] Thus, in certain embodiments, a dialkyl diamide and/or a phosphoric acid ester (e.g., ECF-976 from M-I L.L.C.) or a phosphonic acid ester complexing with a multivalent metal ion (e.g., ferric or aluminum ion, or ECF-977 from M-I
L.L.C.) may be added to disclosed formulations.
[0058] Other gelling agents that may be used include oligovinyl pyrolidone, an oil soluble, very mildly cationic ter-polymer, available from International Specialty Products. Another suitable additive is EMI-759, available from M-I L.L.C.
[0059] Rheological Additives [0060] Suitable rheological additives in accordance with embodiments of the present disclosure, for example, may include alkyl diamides, such as those having a general formula: R1-HN-00-(CH2)n-CO-NH-R2, wherein n is an integer from 1 to 20, more preferably from 1 to 4, yet more preferably from 1 to 2, and R1 is an alkyl groups having from 1 to 20 carbons, more preferably from 4 to 12 carbons, and yet more preferably from 5 to 8 carbons, and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, or more preferably is hydrogen or an alkyl group having from 1 to 4 carbons, wherein R1 and R2 may or may not be identical. Such alkyl diamides may be obtained, for example, from M-I L.L.C. (Houston, TX) under the trade name of VersaPacTM. Other rheological additives include Bentone 150, TruVis, Garamite 1210, VG SupremeTM, and Laponite, which are organophilic clays, and RheThikTm, which is a viscosity modifier available, for example, from M-I L.L.C.
(Houston, TX).
[0061] Various formulations of fluids within the scope of the present invention are provided below as examples. However, the present invention is not limited to the described embodiments, but is bounded by the claims that follow.
[0062] Examples [0063] In selected embodiments, OB WARP (which is disclosed in U.S. Patent No. 6,586,372, assigned to the assignee of the present invention), may be mixed in concentrations ranging
[0057] Thus, in certain embodiments, a dialkyl diamide and/or a phosphoric acid ester (e.g., ECF-976 from M-I L.L.C.) or a phosphonic acid ester complexing with a multivalent metal ion (e.g., ferric or aluminum ion, or ECF-977 from M-I
L.L.C.) may be added to disclosed formulations.
[0058] Other gelling agents that may be used include oligovinyl pyrolidone, an oil soluble, very mildly cationic ter-polymer, available from International Specialty Products. Another suitable additive is EMI-759, available from M-I L.L.C.
[0059] Rheological Additives [0060] Suitable rheological additives in accordance with embodiments of the present disclosure, for example, may include alkyl diamides, such as those having a general formula: R1-HN-00-(CH2)n-CO-NH-R2, wherein n is an integer from 1 to 20, more preferably from 1 to 4, yet more preferably from 1 to 2, and R1 is an alkyl groups having from 1 to 20 carbons, more preferably from 4 to 12 carbons, and yet more preferably from 5 to 8 carbons, and R2 is hydrogen or an alkyl group having from 1 to 20 carbons, or more preferably is hydrogen or an alkyl group having from 1 to 4 carbons, wherein R1 and R2 may or may not be identical. Such alkyl diamides may be obtained, for example, from M-I L.L.C. (Houston, TX) under the trade name of VersaPacTM. Other rheological additives include Bentone 150, TruVis, Garamite 1210, VG SupremeTM, and Laponite, which are organophilic clays, and RheThikTm, which is a viscosity modifier available, for example, from M-I L.L.C.
(Houston, TX).
[0061] Various formulations of fluids within the scope of the present invention are provided below as examples. However, the present invention is not limited to the described embodiments, but is bounded by the claims that follow.
[0062] Examples [0063] In selected embodiments, OB WARP (which is disclosed in U.S. Patent No. 6,586,372, assigned to the assignee of the present invention), may be mixed in concentrations ranging
15 PCT/US2008/071046 from 10-20 w/w% base oil, 2 ¨ 4 w/w% coating additive/dispersant, 0.1 -1 w/w%
emulsifier/dispersant, 0.1 ¨ 1 w/w% lime and 60-90 w/w% barite/weight material.
[0064] In one embodiment, a 19.4 ppg folinulation of OB WARP, was formulated in accordance with embodiments disclosed in U.S. Patent No. 6,586,372, which is assigned to the assignee of the present invention. Specifically, in this embodiment, the OB WARP was mixed with EDC-99DW, which is a paraffin oil, followed by the addition of additional base oil, Bentone 150, and sufficient glycerol to constitute 2%
by volume of the total mixture, on a Hamilton Beach mixer at ambient temperature.
The resulting solution had a final density of 13.6 ppg. After mixing the components, the theological properties of the solution at 170 F were investigated. The rheological measurements were made using a Fann 35 viscometer, available from Fann instrument company.
[0065] Specifically, the apparent viscosity was measured. Viscosity is the ratio of the shear stress to the shear rate and is an indication of flow resistance. For many fluids, apparent viscosity changes for different values of shear rate, and is measured in centipoise (cP). Shear rate is measured in RPM or sec-I. In this embodiment, the initial apparent viscosity was measured at six different shear rates: 600 rpm, rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The results are shown in Table 1, below.
Table 1 Shear Rate (RPM) Initial [0066] In a second embodiment, the rheological properties of an OB WARP
concentrate, formulated in accordance with embodiments disclosed in U.S.
Patent No. 6,586,372 . were investigated at 40 F, 70 F, 120 F, 180 F, 250 F, 300 F,
emulsifier/dispersant, 0.1 ¨ 1 w/w% lime and 60-90 w/w% barite/weight material.
[0064] In one embodiment, a 19.4 ppg folinulation of OB WARP, was formulated in accordance with embodiments disclosed in U.S. Patent No. 6,586,372, which is assigned to the assignee of the present invention. Specifically, in this embodiment, the OB WARP was mixed with EDC-99DW, which is a paraffin oil, followed by the addition of additional base oil, Bentone 150, and sufficient glycerol to constitute 2%
by volume of the total mixture, on a Hamilton Beach mixer at ambient temperature.
The resulting solution had a final density of 13.6 ppg. After mixing the components, the theological properties of the solution at 170 F were investigated. The rheological measurements were made using a Fann 35 viscometer, available from Fann instrument company.
[0065] Specifically, the apparent viscosity was measured. Viscosity is the ratio of the shear stress to the shear rate and is an indication of flow resistance. For many fluids, apparent viscosity changes for different values of shear rate, and is measured in centipoise (cP). Shear rate is measured in RPM or sec-I. In this embodiment, the initial apparent viscosity was measured at six different shear rates: 600 rpm, rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The results are shown in Table 1, below.
Table 1 Shear Rate (RPM) Initial [0066] In a second embodiment, the rheological properties of an OB WARP
concentrate, formulated in accordance with embodiments disclosed in U.S.
Patent No. 6,586,372 . were investigated at 40 F, 70 F, 120 F, 180 F, 250 F, 300 F,
16 350 F, and 400 F, on a Farin 75 viscometer. The results of this testing is shown in Table 2 below.
[0067]
"PV" is plastic viscosity (CPS) which is one variable used in the calculation of viscosity characteristics of a drilling fluid. "YP" is yield point (lbs/100 ft2) which is another variable used in the calculation of viscosity characteristics of drilling fluids.
"GELS" (lbs/100 ft2) is a measure of the suspending characteristics and the thixotropic properties of a drilling fluid.
Table 2 Temp Temp Pressure Pressure 600 300 200 100 6 3 Gel Gel PV VP Ty/YP
Num 10 10 psi bar rpm rpm rpm rpm rpm rpm sec min cp lb/hsf 1 40 4.0 0 0 593 297 184 87 8 5 6 2.33 2 70 21.0 0 0 280 141 92 47 5 3 4 10 139 2 1.06 3 120 49.0 0 0 130 73 51 28 4 2 3 8 57 16 0.05 4 120 49.0 5000 340 217 117 BO 43 5 3 2 10 100 17 0.10 6 120 49.0 10000 680 362 188 126 66 7 5 1 11 174 14 0.21 6 120 49.0 12000 816 444 228 152 78 8 6 1 12 216 12 0.31 7 180 82.0 0 0 81 48 35 21 3 2 3 10 33 15 0.04 8 180 82.0 5000 340 122 71 50 29 4 3 2 11 51 20 0.06 9 180 82.0 10000 680 184 103 73 41 6 4 2 12 81 22 0.09 180 82.0 12000 816 216 120 84 47 6 4 1 13 96 24 0.10..
11 180 82.0 15000 1020 276 150 105 57 7 5 1 13 126 24 0.13 12 180 82.0 20000 1361 415 219 151 80 9 7 1 15 196 23 0,21 13 250 121.0 5000 340 85 51 38 23 4 3 3 16 34 17 0.09 14 250 121.0 10000 680 119 69 51 31 5 4 2 18 50 19 0.12 250 121.0 12000 816 136 78 57 34 6 4 2 18 58 20 0.13 16 250 121.0 15000 1020 166 94 68 40 7 5 2 19 72 22 0.15
[0067]
"PV" is plastic viscosity (CPS) which is one variable used in the calculation of viscosity characteristics of a drilling fluid. "YP" is yield point (lbs/100 ft2) which is another variable used in the calculation of viscosity characteristics of drilling fluids.
"GELS" (lbs/100 ft2) is a measure of the suspending characteristics and the thixotropic properties of a drilling fluid.
Table 2 Temp Temp Pressure Pressure 600 300 200 100 6 3 Gel Gel PV VP Ty/YP
Num 10 10 psi bar rpm rpm rpm rpm rpm rpm sec min cp lb/hsf 1 40 4.0 0 0 593 297 184 87 8 5 6 2.33 2 70 21.0 0 0 280 141 92 47 5 3 4 10 139 2 1.06 3 120 49.0 0 0 130 73 51 28 4 2 3 8 57 16 0.05 4 120 49.0 5000 340 217 117 BO 43 5 3 2 10 100 17 0.10 6 120 49.0 10000 680 362 188 126 66 7 5 1 11 174 14 0.21 6 120 49.0 12000 816 444 228 152 78 8 6 1 12 216 12 0.31 7 180 82.0 0 0 81 48 35 21 3 2 3 10 33 15 0.04 8 180 82.0 5000 340 122 71 50 29 4 3 2 11 51 20 0.06 9 180 82.0 10000 680 184 103 73 41 6 4 2 12 81 22 0.09 180 82.0 12000 816 216 120 84 47 6 4 1 13 96 24 0.10..
11 180 82.0 15000 1020 276 150 105 57 7 5 1 13 126 24 0.13 12 180 82.0 20000 1361 415 219 151 80 9 7 1 15 196 23 0,21 13 250 121.0 5000 340 85 51 38 23 4 3 3 16 34 17 0.09 14 250 121.0 10000 680 119 69 51 31 5 4 2 18 50 19 0.12 250 121.0 12000 816 136 78 57 34 6 4 2 18 58 20 0.13 16 250 121.0 15000 1020 166 94 68 40 7 5 2 19 72 22 0.15
17 250 121.0 20000 1361 230 127 92 53 8 7 1 20 103 24 0.19
18 300 149.0 5000 340 74 44 34 22 5 4 4 24 30 14 0.20
19 300 149.0 10000 680 99 58 44 28 6 _ 4 3 25 41 17 0.21 300 149.0 12000 816 112 65 49 30 6 5 3 26 47 18 0.22 21 300 149.0 15000 1020 133 76 57 35 7 6 2 27 57 19 0.24 22 300 149.0 20000 1361 178 100 74 44 8 7 2 29 78 22 0.26 23 350 177.0 5000 340 69 41 32 21 5 4 5.
37 28 13 0.29 24 350 177.0 10000 680 89 52 40 26 6 5 4 39 37 15 0.31 350 177.0 12000 816 99 57 44 28 7 6 4 40 42 15 0.33 26 350 177.0 15000 1020 116 66 50 32 7 7 3 41 50 16 0.35 27 350 177.0 20000 1361 150 84 64 40 9 8 3 43 66 18 0.38 28 400 204.0 5000 340 67 39 31 21 6 6 7 59 28 11 0.49 29 400 204.0 10000 680 84 48 38 25 7 7 6 62 36 12 0.54 400 204.0 12000 816 93 53 41 28 7 7 5 63 40 13 0.53 31 400 204.0 15000 1020 107 60 47 31 9 8 5 65 47 13 0.59 32 400 204.0 20000 1361 135 75 68 37 11 10 4 68 60 15 0.61 [00691 Exemplary Applications 100701 Wellb ore fluids formulated in accordance with embodiments disclosed herein may be used in stimulation operations. For example, it is believed that a fluid may be useful when injecting CO2 at 400 F into an oil-producing zone.
[0071] In another application, a high density (19.9 ppg) annular fluid may be used in connection with a deep well, where a packer has been emplaced. As is known to those in the art, typical packers employ elastomeric rings to contact the borehole wall to hold the packer in place to isolate zones of a well. If large pressure differentials exist across the packer face, however, the packer will leak or slide.
This can be a significant issue in certain deep wells. Using typical annular fluids, therefore, tends to lead to failures in this type of well, as typical annular fluids have a density of only about 8 ppg. Accordingly, a relatively large AP is seen by the packer. In order to circumvent this, a high density fluid formulated in accordance with an embodiment of the present invention, may "spot" emplaced, as part of a two fluid (or more) system, where the high density fluid is placed on top of the packer in order to avoid the AP on the packer. In addition, because both of the fluids can be formulated as gels, the fluids will not mix with each other.
100721 Those having ordinary skill in the art will appreciate that embodiments disclosed herein may be useful in any application where packer fluids may be used.
[00731 Advantageously, and surprisingly, the present inventors have discovered that annular fluids founulated in accordance with the present disclosure, which have significantly higher solids content than prior art annular fluids, may be used in applications that require higher density than prior art formulations.
Advantageously, annular fluids formulated in accordance with embodiments disclosed herein have very good thermal properties while maintaining sufficient rheological properties.
[0074] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
37 28 13 0.29 24 350 177.0 10000 680 89 52 40 26 6 5 4 39 37 15 0.31 350 177.0 12000 816 99 57 44 28 7 6 4 40 42 15 0.33 26 350 177.0 15000 1020 116 66 50 32 7 7 3 41 50 16 0.35 27 350 177.0 20000 1361 150 84 64 40 9 8 3 43 66 18 0.38 28 400 204.0 5000 340 67 39 31 21 6 6 7 59 28 11 0.49 29 400 204.0 10000 680 84 48 38 25 7 7 6 62 36 12 0.54 400 204.0 12000 816 93 53 41 28 7 7 5 63 40 13 0.53 31 400 204.0 15000 1020 107 60 47 31 9 8 5 65 47 13 0.59 32 400 204.0 20000 1361 135 75 68 37 11 10 4 68 60 15 0.61 [00691 Exemplary Applications 100701 Wellb ore fluids formulated in accordance with embodiments disclosed herein may be used in stimulation operations. For example, it is believed that a fluid may be useful when injecting CO2 at 400 F into an oil-producing zone.
[0071] In another application, a high density (19.9 ppg) annular fluid may be used in connection with a deep well, where a packer has been emplaced. As is known to those in the art, typical packers employ elastomeric rings to contact the borehole wall to hold the packer in place to isolate zones of a well. If large pressure differentials exist across the packer face, however, the packer will leak or slide.
This can be a significant issue in certain deep wells. Using typical annular fluids, therefore, tends to lead to failures in this type of well, as typical annular fluids have a density of only about 8 ppg. Accordingly, a relatively large AP is seen by the packer. In order to circumvent this, a high density fluid formulated in accordance with an embodiment of the present invention, may "spot" emplaced, as part of a two fluid (or more) system, where the high density fluid is placed on top of the packer in order to avoid the AP on the packer. In addition, because both of the fluids can be formulated as gels, the fluids will not mix with each other.
100721 Those having ordinary skill in the art will appreciate that embodiments disclosed herein may be useful in any application where packer fluids may be used.
[00731 Advantageously, and surprisingly, the present inventors have discovered that annular fluids founulated in accordance with the present disclosure, which have significantly higher solids content than prior art annular fluids, may be used in applications that require higher density than prior art formulations.
Advantageously, annular fluids formulated in accordance with embodiments disclosed herein have very good thermal properties while maintaining sufficient rheological properties.
[0074] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
Claims (20)
1. A method of preventing hydrate formation during oil production through a subsea field or permafrost layer, comprising:
preparing the packer fluid comprising:
a hydrocarbon fluid, and a micronized weighting agent, wherein the micronized weighting agent has a particle size d90 of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%;
pumping the packer fluid into an annulus; and producing an oil from a formation through a pipe extending through the packer fluid.
preparing the packer fluid comprising:
a hydrocarbon fluid, and a micronized weighting agent, wherein the micronized weighting agent has a particle size d90 of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%;
pumping the packer fluid into an annulus; and producing an oil from a formation through a pipe extending through the packer fluid.
2. The method of claim 1, wherein the micronized weighting agent is at least one selected from barite, calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, hausmannite, and strontium sulfate.
3. The method of claim 1, wherein the micronized weighting agent is coated with a dispersant made by the method comprising dry blending a micronized weighting agent and a dispersant to form a micronized weighting agent coated with the dispersant.
4. The method of claim 1, wherein the micronized weighting agent comprises colloidal particles having a coating thereon.
5. The method of claim 1, wherein the micronized weighting agent has a particle size d90 of less than about 10 microns.
6. The method of claim 1, wherein the micronized weighting agent has a particle size d90 of less than about 5 microns.
7. The method of claim 3, wherein the coating comprises at least one selected from the free acid or alkaline salts of oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acids, polyacrylate esters, and phospholipids.
8. The method of claim 1, wherein the packer fluid further comprises a rheological additive.
9. The method of claim 8, wherein the rheological additive is an alkyl diamide having a formula: R1-HN-CO-(CH2)n-CO-NH-R2, wherein n is an integer from 1 to 20, R1 is an alkyl groups having from 1 to 20 carbons, and R2 is hydrogen or an alkyl group having from 1 to 20 carbons.
10. The method of claim 8, wherein the rheological additive is an organophilic clay.
11. The method of claim 1, wherein the hydrocarbon fluid comprises at least one selected from diesel, a mixture of diesels and paraffin oil, mineral oil, and isomerized olefins.
12. The method of claim 1, wherein the packer fluid further comprises a gelling agent.
13. The method of claim 12, wherein the gelling agent comprises a multivalent metal ion and at least one ester selected from the group consisting of a phosphoric acid ester and a phosphonic acid ester.
14. The method of claim 13, wherein the multivalent metal ion is at least one selected from the group consisting of a ferric ion and an aluminum ion.
15. The method of claim 12, wherein the gelling agent comprises an ionic polymer.
16. The method of claim 1, wherein the packer fluid further comprises glycerol.
17. A method for stimulating a well, comprising preparing the packer fluid comprising:
a hydrocarbon fluid, and a coated micronized weighting agent, wherein the micronized weighting agent has a particle size d90of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%;
pumping the packer fluid into an annulus; and injecting hot-water or steam through a pipe extending through the packer fluid.
a hydrocarbon fluid, and a coated micronized weighting agent, wherein the micronized weighting agent has a particle size d90of less than 20 microns, and wherein the micronized weighting agent is present at a concentration of 60-90 w/w%;
pumping the packer fluid into an annulus; and injecting hot-water or steam through a pipe extending through the packer fluid.
18. The method of claim 1, wherein the packer fluid is pumped into the annulus above a packer.
19. The method of claim 17, wherein the packer fluid is pumped into the annulus above a packer.
20. The method of claim 1, wherein the method of preventing hydrate formation occurs through a subsea field in waters having a temperature in the range of 32°F to 50°F (0°C
to 10°C).
to 10°C).
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US95274107P | 2007-07-30 | 2007-07-30 | |
| US60/952,741 | 2007-07-30 | ||
| PCT/US2008/071046 WO2009023415A2 (en) | 2007-07-30 | 2008-07-24 | Insulating annular fluid |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2694951A1 CA2694951A1 (en) | 2009-02-19 |
| CA2694951C true CA2694951C (en) | 2015-11-17 |
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Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2694951A Active CA2694951C (en) | 2007-07-30 | 2008-07-24 | Insulating annular fluid |
Country Status (6)
| Country | Link |
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| EP (1) | EP2188346A4 (en) |
| AR (1) | AR067738A1 (en) |
| CA (1) | CA2694951C (en) |
| EA (1) | EA201070205A1 (en) |
| PA (1) | PA8791501A1 (en) |
| WO (1) | WO2009023415A2 (en) |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB201109446D0 (en) * | 2011-06-06 | 2011-07-20 | M I Drilling Fluids Uk Ltd | Methods for reducing permeability of subterranean reservoirs |
| US10400155B2 (en) | 2012-07-09 | 2019-09-03 | M-I L.L.C. | Insulating annular fluid |
| WO2014085770A1 (en) * | 2012-11-29 | 2014-06-05 | M-I L.L.C. | Colloidal silica and polymer system for insulating packer fluids |
| CN105112026B (en) * | 2015-03-07 | 2018-07-17 | 中石化石油工程技术服务有限公司 | A kind of preparation method and purposes of drilling fluid ultra high density powder body heavy weight additive |
Family Cites Families (18)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3613792A (en) | 1969-12-11 | 1971-10-19 | British Petroleum Co | Oil well and method for production of oil through permafrost zone |
| US3827978A (en) * | 1970-12-14 | 1974-08-06 | Atlantic Richfield Co | Packer fluid for drilling and completing a well |
| US3852202A (en) * | 1972-10-19 | 1974-12-03 | Dresser Ind | Inert packer fluid additive comprising asbestos and fumed alumina |
| US4258791A (en) | 1980-01-29 | 1981-03-31 | Nl Industries, Inc. | Thermal insulation method |
| FR2518896A1 (en) | 1981-12-29 | 1983-07-01 | Schlumberger Cie Dowell | PROCESS FOR OBTAINING GELIFIED HYDROCARBON COMPOSITIONS, COMPOSITIONS OBTAINED AND THEIR USE IN THE HYDRAULIC FRACTURING OF UNDERGROUND FORMATIONS |
| US4528104A (en) | 1982-08-19 | 1985-07-09 | Nl Industries, Inc. | Oil based packer fluids |
| US4622155A (en) * | 1984-03-13 | 1986-11-11 | Halliburton Company | Method for fracturing subterranean formations |
| US5190675A (en) | 1985-12-12 | 1993-03-02 | Dowell Schlumberger Incorporated | Gelling organic liquids |
| US5607901A (en) * | 1995-02-17 | 1997-03-04 | Bp Exploration & Oil, Inc. | Environmentally safe annular fluid |
| US5846915A (en) | 1995-10-26 | 1998-12-08 | Clearwater, Inc. | Delayed breaking of gelled hydrocarbon fracturing fluid |
| GB2315505B (en) | 1996-07-24 | 1998-07-22 | Sofitech Nv | An additive for increasing the density of a fluid and fluid comprising such additve |
| US7267291B2 (en) | 1996-07-24 | 2007-09-11 | M-I Llc | Additive for increasing the density of an oil-based fluid and fluid comprising such additive |
| US20030203822A1 (en) | 1996-07-24 | 2003-10-30 | Bradbury Andrew J. | Additive for increasing the density of a fluid for casing annulus pressure control |
| US6786153B2 (en) | 2002-09-19 | 2004-09-07 | Interflex Laser Engravers, Llc | Printing rolls having wear indicators and methods for determining wear of printing and anilox rolls and sleeves |
| US6511944B2 (en) | 2001-02-23 | 2003-01-28 | Halliburton Energy Services, Inc. | Methods and compositions for treating subterranean formations with gelled hydrocarbon fluids |
| EA010612B1 (en) | 2004-06-03 | 2008-10-30 | М-Ай Л. Л. С. | The use of sized barite as a weighting agent for drilling fluids |
| US7334639B2 (en) * | 2005-09-30 | 2008-02-26 | M-I Llc | In-situ solidification of invert emulsion fluids to form gas tight annular barrier |
| EP2481883A3 (en) * | 2005-10-03 | 2013-12-18 | M-I L.L.C. | Oil-based insulating packer fluid |
-
2008
- 2008-07-24 WO PCT/US2008/071046 patent/WO2009023415A2/en active Application Filing
- 2008-07-24 EP EP08827556A patent/EP2188346A4/en not_active Ceased
- 2008-07-24 EA EA201070205A patent/EA201070205A1/en unknown
- 2008-07-24 CA CA2694951A patent/CA2694951C/en active Active
- 2008-07-30 PA PA8791501A patent/PA8791501A1/en unknown
- 2008-07-30 AR ARP080103292 patent/AR067738A1/en not_active Application Discontinuation
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| WO2009023415A3 (en) | 2009-09-03 |
| EP2188346A4 (en) | 2011-04-20 |
| EP2188346A2 (en) | 2010-05-26 |
| WO2009023415A2 (en) | 2009-02-19 |
| AR067738A1 (en) | 2009-10-21 |
| EA201070205A1 (en) | 2010-08-30 |
| PA8791501A1 (en) | 2009-04-23 |
| CA2694951A1 (en) | 2009-02-19 |
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