• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    COMPOSITES FOR CONTROLLED RELEASE OF WELL TREATMENT AGENTS. The present invention relates to a well treatment composite that allows the slow release of one or more well treatment agents in an underground formation and / or a well drilling penetrating the formation has a nano-sized calcined porous substrate ( adsorbent) with a high surface area over which the well treatment agent is applied. Composites are suitable for use in such well treatment operations as hydraulic fracture and sand control.
    公开号:BR112013027230B1
    申请号:R112013027230-9
    申请日:2012-04-20
    公开日:2021-01-26
    发明作者:D.V. Satyanarayana Gupta
    申请人:Baker Hughes Incorporated；
    IPC主号:
    专利说明:

    [0001] [0001] Composites containing at least one well treatment agent and a calcined porous metal oxide can be used in well treatment operations in order to slowly release the well treatment into the surrounding environment. Background of the Invention
    [0002] [0002] Fluids produced from wells typically contain a complex mixture of components including aliphatic, aromatic hydrocarbons, hetero-atomic molecules, anionic and cationic salts, acids, sands, silt and clays. The nature of these fluids, combined with the severe conditions of heat, pressure, and turbulence to which they are frequently subjected, are factors that contribute to the formation of fouling, salt formation, paraffin deposition, emulsification (both water-in-oil and oil-in-water), formation of gaseous hydrate, corrosion, precipitation of alphalene and formation of paraffin in oil and / or gas production wells and surface equipment. Such conditions, in turn, decrease the permeability of underground formation and thus reduce well productivity. In addition, such conditions shorten the life span of production equipment. In order to clean deposits of wells and equipment, it is necessary to interrupt production, which is both time consuming and expensive.
    [0003] [0003] Well treatment agents are often used in production wells to avoid the harmful effects caused by such deposits and precipitates. For example, scale formation in the formation (as well as on production lines going down the hole) is often controlled through the use of scale inhibitors.
    [0004] [0004] Various processes are known in the art for introducing well treatment agents into production wells. For example, a liquid well treatment agent can be forced into the formation by applying hydraulic pressure from the surface that forces the treatment agent into the targeted area. In most cases, such treatments are performed at orifice injection pressures below that of the formation fracture pressure. Alternatively, the release process may consist of placing a solid well treatment agent in the formation of production in conjunction with a hydraulic fracture operation. This process is often preferred because it puts the agent for treatment in contact with fluids contained in the formation before such fluids enter the well orifice where harmful effects are commonly encountered.
    [0005] [0005] A major disadvantage of such processes is the difficulty in releasing the agent to treat the well in the well for a sustained period of time. As a result, treatment has to be undertaken repeatedly to ensure that the required level of agent for treatment is continually present in the well. Such treatments result in loss of production income due to non-productive interval.
    [0006] [0006] Treatment processes have therefore been sought for the introduction of well treatment agents in oil and / or gas wells where the treatment agent can be released for a sustained period of time and where continued attention from operators for prolonged periods it is unnecessary.
    [0007] [0007] US 7,491,682 and US 7,493,955 reveal processes for treating a well through the use of a composite containing an agent for treating well adsorbed onto carrier materials with a high surface area. Such composites can be used for slow release of treatment agents from wells in the formation and the surroundings. They have been used in several formations including deep water, hermetic formations of coal bed and gas methane. US 7,686,081 and US 2010/0175875 reveal refilling of such particles once they have been depleted.
    [0008] [0008] Such composites, however, often have an inherent disadvantage in that they do not exhibit the required strength of solid materials for hydraulic fracture maintenance and thus usually have to be mixed in less than 10% by weight of the solid material for fracture maintenance or control treatment with sand.
    [0009] [0009] Higher loads result in crushing of the composites, resulting in a loss of packaging conductivity.
    [0010] [00010] Therefore, there is a need to develop well treatment composites that exhibit the resistance of a solid fracture maintenance material and are still characterized by a high surface area so that the composite load in a solid material package fracture maintenance can be increased. Summary of the Invention
    [0011] [00011] A composite for treatment of wells can be used in stimulation of a well being introduced in an underground formation or in the drilling of a well penetrating the underground formation. The well treatment composite exhibits the strength of a solid material for maintaining conventional hydraulic fracture while still allowing the slow release of one or more well treatment agents in the formation and / or drilling of the well. In some examples, the pit treatment composite can be used as the hydraulic fracture maintenance material per se.
    [0012] [00012] The well treatment composite can be used in stimulation treatments as a component of a fracturing fluid or acidulating fluid, such as an acidulating matrix fluid. The composite has particular application in completion fluids containing zinc bromide, calcium bromide, calcium chloride and sodium bromide pickles. Such fluids can be introduced below the annulus of the well and, when desired, washed with produced water.
    [0013] [00013] The well treatment composite has a nano-sized calcined porous substrate (adsorbent) with a high surface area over which the well treatment agent is applied. When used in an oil, gas or geothermal well or an underground formation penetrated by such a well, the well treatment agent is slowly released from the adsorbent and can be slowly released into a package of solid hydraulic fracture maintenance material.
    [0014] [00014] Suitable substrates are calcined metal oxides and include alumina, zirconium oxide and titanium oxide.
    [0015] [00015] In a particularly preferred embodiment, the composites of the invention are used in wells in order to inhibit scale formation, control scale formation or delay the release of scale inhibitors in the well. For example, the composite can be used in completion or production services. The composites of the invention can be used in the well to remove unwanted contaminants from, or to control the formation of unwanted contaminants on tubular surface equipment within well drilling. Brief Description of Drawings
    [0016] [00016] In order to understand more fully the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, where:
    [0017] [00017] FIG. 1A and FIG. 1B are release profiles of a fouling inhibitor in high-strength composites containing porous alumina adsorbents between 0 to 2500 pore volumes and 0 to 10,000 pore volumes, respectively.
    [0018] [00018] FIG. 2 is a release profile of a fouling inhibitor in high-strength composites containing porous alumina adsorbent of variable diameter between 0 to 2000 pore volumes.
    [0019] [00019] FIG. 3 is a release profile of a scale inhibitor in high strength composites containing porous alumina adsorbent of varying diameter using a sand pack using 50% of the particles as in FIG. two.
    [0020] [00020] FIG. 4A and FIG. 4B are release profiles of a fouling inhibitor in high-strength composites containing porous alumina adsorbents of varying diameters and sizes between 0 to 4000 pore volumes and 0 to 10,000 pore volumes, respectively. Detailed Description of Preferred Achievements
    [0021] [00021] The composite for treatment of wells for use in the treatment of wells or an underground formation is characterized by a porous calcined substrate prepared of nano-size material on which at least one agent for treatment can be adsorbed.
    [0022] [00022] The porosity and permeability of the calcined porous substrate is such that the agent for treating wells can also be absorbed in the interstitial spaces of the porous substrate. Typically, the surface area of the calcined porous substrate is between about 1 m2 / g and about 10 m2 / g, preferably between about 1.5 m2 / g and about 4 m2 / g, the diameter of the calcined porous substrate is between about from 0.1 to about 3 mm, preferably between about 150 to about 1780 micrometers, and the pore volume of the calcined porous substrate is between about 0.01 to about 0.10 g / cm3.
    [0023] [00023] The well treatment agent is generally capable of being dissolved at a generally constant rate over an extended period of time in the aqueous fluid, water or hydrocarbon liquid contained in the underground formation contained in the underground formation.
    [0024] [00024] Typically, the specific weight of the composite for well treatment is less than or equal to 3.75 g / cm3.
    [0025] [00025] Porous metal oxide is typically spherical and insoluble in well fluids under underground conditions, such as at temperatures of less than about 250 ° C, and pressures of less than about 80 MPa.
    [0026] [00026] The porous substrate can be a metal oxide, such as alumina, zirconium oxide and titanium oxide. Typically, the porous substrate is alumina.
    [0027] (a) mistura de hidrossol de óxido de metal (tal como hidrossol de óxido de alumínio) contendo um hidrato do óxido de metal ou metal ativado (tal como alumina ativada) e um componente aditivo selecionado de carbono (tal como negro de fumo) ou um material orgânico natural de alto peso molecular (tal como serragem e amido) que é insolúvel em solução aquosa até uma temperatura de 50°C e carbono com uma solução de base hidrolisável para formar uma mistura; (b) introdução de mistura em forma dispersa em um líquido imiscível em água tendo uma temperatura de cerca de 60°C a 100°C, pelo que partículas de gel são formadas; (c) envelhecimento de partículas de gel no líquido na temperatura e subsequentemente em uma base aquosa, tal como uma solução aquosa de amônia; (d) recuperação de partículas envelhecidas; e então (e) calcinação de partículas recuperadas. Durante calcinação, o componente aditivo é removido. As partículas calcinadas têm uma densidade de volume menor quando o componente aditivo está presente durante calcinações do que quando o componente aditivo não está presente. Tipicamente, a densidade de volume do compósito para tratamento de poço está entre cerca de 1,2 g/cm3 (75 lb/ft3) a cerca de 2,4 g/cm3 (150 lb/ft3). Em adição, combustão do componente aditivo durante calcinações do hidrossol resulta em formação de poros do óxido de metal calcinado. [00027] The adsorbent can be prepared using: (a) mixture of metal oxide hydrosol (such as aluminum oxide hydrosol) containing an activated metal or metal oxide hydrate (such as activated alumina) and a selected carbon additive component (such as carbon black) or a high molecular weight natural organic material (such as sawdust and starch) that is insoluble in an aqueous solution up to a temperature of 50 ° C and carbon with a hydrolyzable base solution to form a mixture; (b) introducing mixture in dispersed form in a water immiscible liquid having a temperature of about 60 ° C to 100 ° C, whereby gel particles are formed; (c) aging of gel particles in the liquid at temperature and subsequently in an aqueous base, such as an aqueous ammonia solution; (d) recovery of aged particles; and then (e) calcination of recovered particles. During calcination, the additive component is removed. The calcined particles have a lower volume density when the additive component is present during calcination than when the additive component is not present. Typically, the volume density of the well treatment composite is between about 1.2 g / cm3 (75 lb / ft3) to about 2.4 g / cm3 (150 lb / ft3). In addition, combustion of the additive component during hydrosol calcinations results in the formation of pores of the calcined metal oxide.
    [0028] [00028] The metal oxide hydrosol can optionally contain a substance containing silica which in its non-soluble form is co-precipitated with the metal oxide particles. The silica-containing substance is preferably a low-density silica, such as that prepared by hydrolysis of silicon tetrachloride in an oxy-hydrogen flame and known under the name of fumed silica.
    [0029] [00029] In one embodiment, spherical metal oxide adsorbent can be prepared from concentrated metal oxide hydrosol of a pH value in the range of about 3 to about 5 which, in turn, is prepared by dissolving metal in hydrochloric acid and / or metal chloride in aqueous solution or by dissolving hydroxy metal chloride in water, the concentration of which is adjusted so that the metal oxide derived from the sol totals 15 to 35% by weight, preferably 20 to 30% by weight of the mass of the calcined particles. Metal oxide and / or activated metal hydrate, preferably of an average particle diameter of a maximum of 10 microns, is then added to the hydrosol in an amount so that the metal oxide content totals 65 to 85% by weight, preferably 70 to 80% by weight of the calcined particles. Optionally, fumed silica can be added to the hydrosol so that the SiO2 content of the calcined particles totals 10 to 40% by weight. A soft to medium-hard sawdust can then be added to the mixture, the sawdust being ground to a finer particle size so that it is present in an amount of 5 to 35% by weight, preferably 10 to 25% by weight. relation to the mass of the calcined particles. The sawdust-containing hydrosol can then be mixed with a concentrated solution of hexa methylene tetra amine and then sprinkled or dripped onto a column filled with mineral oil at a temperature of 60 ° C to 100 ° C. The gel particles are then allowed to remain at the precipitation temperature for a period of 4 to 16 hours; then the gel particles are aged for 2 to 8 hours in aqueous ammonia solution, washed with water, dried at 100 ° C to 150 ° C, or preferably from about 120 ° C to about 200 ° C, pre- heated to 250 ° C to 400 ° C and calcined at a temperature of 600 ° C to about 1000 ° C.
    [0030] [00030] Alternative processes for making metal oxide adsorbent are further shown in US 4,013,587, incorporated herein by reference.
    [0031] [00031] In a preferred embodiment, when the metal oxide adsorbent is alumina adsorbent, the adsorbent can be prepared by hydrolysis of aluminum alkoxides to yield nano-sized alumina, drying to remove water and then introducing dried aluminum into a dispersed form in an oil at a temperature of about 60 to 100 ° C, so that gel particles are formed. The gel particles are then aged in the liquid and subsequently in an aqueous ammonia solution, recovered and then calcined. Nano-sized alumina can be produced having an average diameter in the range of about 0.4 mm to about 1 mm.
    [0032] [00032] The amount of well treatment agent in the composite is usually about 1 to 50 weight percent, preferably about 14 to about 40 weight percent.
    [0033] [00033] The well treatment agent is preferably soluble in water or soluble in aliphatic and aromatic hydrocarbons. When fluid is produced, the well treatment agent can desorb into its respective solubilizing liquid. For example, where a solid well treatment is an inhibitor for fouling, corrosion, the action of salts or biocides, the treatment agent can desorb into produced water. In the absence of water flow, the well treatment agent can remain intact on the solid adsorbent. As another example, solid inhibitors for paraffin or asphaltene can desorb in the produced fluid hydrocarbon phase.
    [0034] [00034] In a preferred embodiment, the well treatment agent can be at least one member selected from the group consisting of demulsifying agents (both water-in-oil or oil-in-water), corrosion inhibitors, scale inhibitors , paraffin inhibitors, gas hydrate inhibitors, salt formation inhibitors, and asphaltene dispersants as well as mixtures thereof.
    [0035] [00035] Still, other suitable treatment agents include foaming agents, oxygen scavengers, biocides and surfactants as well as other agents where slow release into the production well is desired.
    [0036] [00036] Adsorption of the well treatment agent on the adsorbent reduces (or eliminates) the amount of well treatment agent required to be in solution. Since the well treatment agent is adsorbent on a substrate, only a small amount of well treatment agent can be released into the aqueous medium.
    [0037] [00037] The well treatment agent is preferably a liquid material. If the well treatment agent is a solid, it can be dissolved in an appropriate solvent, thus making it a liquid.
    [0038] [00038] The composites defined herein are used in well treatment compositions such as fluids used to treat gas wells or oil wells where it is desired to inhibit the formation of unwanted contaminants, control the formation of unwanted contaminants or delay release of unwanted contaminants in the well. For example, the composite can be used in completion or production services. The composites of the invention can be used in the well to remove unwanted contaminants from the well or to control the formation of unwanted contaminants on tubular surface equipment within the well drilling.
    [0039] [00039] In a preferred embodiment, the well treatment composite of the invention effectively inhibits, controls, prevents or treats the formation of inorganic scale being deposited in underground formations, such as well boreholes, oil wells, gas wells, wells of water and geothermal wells. The composites of the invention are particularly effective in the treatment of calcium salt, barium, magnesium scale and the like, including barium sulfate, calcium sulfate scale and calcium carbonate scale. Composites may still have applicability in the treatment of other inorganic scale, such as zinc sulfide, iron sulfide, etc.
    [0040] [00040] The well treatment composite can also be used to control and / or prevent the unwanted formation of salts, paraffins, gas hydrates, asphaltenes as well as corrosion in formations or on surface equipment. Still, other suitable treatment agents include foaming agents, oxygen scavengers, biocides, emulsifiers (both water-in-oil and oil-in-water) and surfactants as well as other agents can be used with the adsorbent that is desired to slow the release of such agents in the production well.
    [0041] [00041] Appropriate fouling inhibitors are anionic fouling inhibitors.
    [0042] [00042] Preferred scale inhibitors include strong acidic materials such as a phosphonic acid, a phosphoric acid, or a phosphorous acid, phosphate esters, phosphonate / phosphonic acids, the various polycarboxylic amino acids, chelating agents, and polymeric inhibitors and their salts . Organo phosphonates, organo phosphates, and phosphate esters as well as their corresponding acids and salts are included.
    [0043] [00043] Phosphonic acid / phosphonate-type scale inhibitors are often preferred in light of their effectiveness in controlling scale in relatively low concentration. Polymeric scale inhibitors, such as polyacrylamides, acrylamide copolymer salts - methyl propane sulfonate / acrylic acid (AMPS / AA), phosphorphic maleic copolymer (PHOS / MA) or sodium salt of poly maleic acid / acrylic acid / salt acrylamido - methyl propane sulfonate (PMA / AMPS), are also effective scale inhibitors. Sodium salts are preferred.
    [0044] [00044] Still useful, especially for pickles, are chelating agents, including diethylene amino penta methylene phosphonic acid and ethylene diamino tetra acetic acid.
    [0045] [00045] The well treatment agent can still be any of the fructans or fructan derivatives, such as inulin and inulin derivatives, as shown in US 2009/0325825, incorporated herein by reference.
    [0046] Examples of demulsifying agents that are useful include, but are not limited to, condensation polymers of alkylene oxides and glycols, such as ethylene oxide and propylene oxide condensation polymers of dipropylene glycol as well as trimethylol propane; and alkyl-substituted phenol formaldehyde resins, bis-phenyl diepoxides, and esters and diesters of such difunctional products. Especially preferred as non-ionic demulsifiers are oxyalkylated phenol formaldehyde resins, oxyalkylated amines and polyamines, di-epoxidated oxyalkylated polyethers, etc. Suitable oil-in-water demulsifiers include quaternary amine poly triethanol methyl chloride, melamine acid colloid, methylated amino polyacrylamide, etc.
    [0047] [00047] Paraffin inhibitors useful for the practice of the present invention include, but are not limited to, ethylene / vinyl acetate copolymers, acrylates (such as polyacrylate esters and methacrylate esters of fatty alcohols), and olefin / maleic esters.
    [0048] Exemplary corrosion inhibitors useful for practicing the invention include, but are not limited to, fatty imidazolines, alkyl pyridines, quaternary alkyl pyridines, fatty quaternary amines and fatty imidazoline salts.
    [0049] [00049] Chemical compounds or inhibitors treating gas hydrates that are useful for the practice of the present invention include, but are not limited to, polymers and homopolymers and copolymers of vinyl pyrrolidone, vinyl capro lactam, and amine-based hydrate inhibitors such such as those shown in US 2006/0223713 and US 2009/0325823, both of which are incorporated herein by reference.
    [0050] [00050] Chemical compounds treating exemplary asphaltenes include, but are not limited to, fatty ester homopolymers and copolymers (such as polymeric fatty esters and copolymers of acrylic and methacrylic acid) and sorbitan monooleate.
    [0051] [00051] Suitable foaming agents include, but are not limited to, oxyalkylated sulphates or ethoxylated alcohol sulphates, or mixtures thereof.
    [0052] [00052] Exemplary surfactants include cationic, amphoteric, anionic and non-ionic surfactants. Included as cationic surfactants are those containing a quaternary ammonium half (such as a linear quaternary amine, a quaternary benzyl amine or a quaternary ammonium halide), a quaternary sulfonium half or a quaternary phosphonium half or mixtures thereof. Suitable surfactants containing a quaternary group include quaternary ammonium halide or quaternary amine, such as quaternary ammonium chloride or a quaternary ammonium bromide. Included as amphoteric surfactants are glycinates, anfoacetates, propionates, betaines and mixtures thereof. The cationic or amphoteric surfactant can have a hydrophobic tail (which can be saturated or unsaturated) such as a C12-C18 carbon chain length. In addition, the hydrophobic tail can be obtained from a natural oil from plants such as one or more coconut oil, rapeseed oil, and palm oil.
    [0053] [00053] Preferred surfactants include N, N, N-trimethyl-1-octa deca ammonium chloride; N, N, N-trimethyl-1-hexa deca ammonium chloride; and N, N, N-trimethyl-1-soy ammonium chloride, and mixtures thereof. Suitable anionic surfactants are sulfonates (such as xylene sulfonate and sodium naphthalene sulfonate), phosphonates, ethoxysulfates and mixtures thereof.
    [0054] [00054] Exemplary oxygen scavengers include triazines, maleimides, formaldehydes, amines, carboxamides, alkyl carboxyl azo compounds, cumine-peroxide compounds, morpholino and amino derivatives and piperazine derivatives, amine oxides, alkanol amines, aliphatic and aromatic polyamines.
    [0055] [00055] The composite of the invention does not require excessive amounts of well treatment agents. The amount of well treatment agent in the composite is that amount sufficient to effect the desired result over a sustained period of time and can be as low as 1 ppm. Generally, the amount of well treatment agent in the composite is about 0.05 to about 5 (preferably about 0.1 to about 2) weight percent based on the total weight of the composite.
    [0056] [00056] When placed in a well, the well treatment agent slowly dissolves at a generally constant rate over an extended period of time in the water or hydrocarbons that are contained in the formation and / or well. The composite therefore allows for a continuous supply of the agent for treating the well in the targeted area. Generally speaking, the lifetime of a single treatment using the composite of the invention is between six and twelve months and can be in excess of 3 years depending on the volume of water or hydrocarbons produced in the production well and the amount of agent for treating the well bonded to calcined porous metal oxide.
    [0057] [00057] Adsorption of the well treatment agent on the porous metal oxide and in the interstitial spaces of the oxide reduces (or eliminates) the amount of well treatment agent required to be in solution. In light of the physical interaction between the well treatment agent and porous metal oxide, only a small amount of well treatment agent can be released into the aqueous medium or hydrocarbon.
    [0058] [00058] For example, where the well treatment agent is a scale inhibitor, the amount of scale inhibitor released from the composite is that amount required to prevent, or at least substantially reduce, the degree of scale formation. For most applications, the amount of scale inhibitor released from the well treatment composite can be as low as 0.1 ppm. Operating costs are therefore significantly reduced.
    [0059] [00059] When the oil field fluid passes through or circulates around well treatment composites, the well treatment agent slowly desorbs. In doing so, composites are characterized by release capabilities with time. Gradual desorption of well treatment agents ensures that they are available for fluids produced for extended periods of time, typically extending over periods of time greater than one year and even as long as five years. Typically the resulting concentration of the well treatment agent in the well drilling is between about 1 to about 50 ppm and can be as low as 1 ppm. Such small amounts of well-treating agent may be sufficient for up to 1000 pore volumes.
    [0060] [00060] The composites of the invention can be used with treatment fluids or carriers in order to facilitate placement of the composite in a desired location within the formation. In this sense, any carrier fluid suitable for transportation of composite can be used. Well treatment compositions containing the composite can be gelled or non-gelled. In one embodiment, the well treatment composites described herein can be introduced or pumped into a well as particles floating neutronically in, for example, a carrier fluid of saturated sodium chloride solution or a carrier fluid that is any other completion brine. or known invasive techniques. Suitable carrier fluids include or can be used in combination with fluids having gelling agents, crosslinking agents, gel breakers, surfactants, foaming agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof.
    [0061] [00061] The carrier fluid can be a brine (such as a saturated solution of potassium chloride or sodium chloride), salt water, fresh water, a liquid hydrocarbon, or a gas such as carbon dioxide or nitrogen. The amount of composite present in the well treatment composition is typically between about 15 ppm to about 100,000 ppm depending on the severity of the scale deposition. Suitable compositions include fracturing fluids, completion fluids, acidulating compositions, etc.
    [0062] [00062] Well treatment compositions containing composites can be used in treatment operations close to well drilling in nature (affecting regions close to well drilling) and can be directed towards improving productivity of well drilling and / or control production of solid material for fracture maintenance or formation sand. Particular examples include gravel packing and, frac packs and water packs. In addition, such particles can be used alone as sand control particles / solid hydraulic fracture maintenance material, or in mixtures in quantities and with types of fracture maintenance sand / solid control materials, such as conventional particle particles. control of sand or fracture. In such applications, the composite can be used in conjunction with sand control particles or solid hydraulic fracture maintenance material.
    [0063] [00063] Such sand control particles or solid hydraulic fracture maintenance material can be a conventional particulate material used in hydraulic fracture or sand control operations, for example, sand ((having an apparent specific weight (ASG), API RP 60, 2.65)) or bauxite (having an ASG of 3.55). Alternatively, the sand control particles or solid hydraulic fracture maintenance material can be "relatively light weight", defined as particles that have an ASG (API RP 56) that is less than 2.45, more preferably less than or equal to 2.0, even more preferably less than or equal to 1.75, more preferably less than or equal to 1.25. Such different types of particles can be selected, for example, to obtain a combination of different specific weights or densities in relation to the selected carrier fluid. For example, a combination of three different particles can be selected for use in a water fracture treatment to form a combination of well treatment particles having three different specific weights, such as an ASG of the first particle type of about 1 unless about 1.5; an ESG of the second type of particles greater than about 1.5 to about 2.0; and ASG of the third particle type from about greater than about 2.0 to about 3.0; or in a specific embodiment the three types of particles having respective specific weights of about 2.65, about 1.7 and about 1.2. In one example, at least one of the selected well treatment particle types can be selected to be substantially neutronically fluctuating in the selected treatment fluid or carrier.
    [0064] [00064] In some examples, the well treatment composition may contain between about 1 to about 99% by weight of hydraulic fracture maintenance material.
    [0065] [00065] In other examples, the composite defined herein is strong enough at high pressures to be used as a hydraulic fracture maintenance material in hydraulic fracture operations including temperatures in excess of 250 ° C and pressures in excess of 80 MPa.
    [0066] [00066] For example, when used in hydraulic fracture and / or sand control treatments, porous particles can be selected to exhibit crushing resistance under conditions as high as 10,000 psi of closing stress, API RP 56 or API RP 60, generally between about 250 to about 8000 psi of closing voltage.
    [0067] [00067] The inventive composites are particularly effective in hydraulic fracture as well as sand control fluids such as water, brine, water with chemical additives such as water fracture treatments with chemical additives in relatively low concentrations for obtaining partial monolayer fractures , low concentration polymer gel fluids (linear or crosslinked), foam fluids (with gas), liquid gas such as liquid carbon dioxide fracture treatments for deeper penetration of solid hydraulic fracture maintenance material, treatments for sensitive areas water, and treatments for gas storage wells.
    [0068] [00068] When used in hydraulic fracture, the composite can be injected into an underground formation in conjunction with a hydraulic fracture fluid at pressures high enough to cause the formation or increase of fractures. Since the particles can withstand temperatures greater than 370 ° C, and closing stresses greater than about 8000 psi, they can be used as particles of solid hydraulic fracture maintenance material. Alternatively, the composite can be used in conjunction with a conventional solid hydraulic fracture maintenance material. Since the porous particles of the composite are insoluble, the composite can continue to function as a solid hydraulic fracture maintenance material even after the well treatment agent has been completely leached from the composite.
    [0069] [00069] Fluids containing well treatment composites can be used to optimize hydraulic fracture geometries and improve well productivity. As an example, fluids can be used to obtain increased fracture length with solid material in relatively gas-resistant formations. Choice of different particulate materials and their quantities for use in such combinations can be made on the basis of one or more well treatment considerations including, but not limited to, well treatment objective (s), such as for sand control and / or for creating fractures with solid fracture maintenance material, well treatment fluid characteristics, such as apparent specific weight and / or carrier fluid rheology, well conditions and formation such as depth of formation, porosity / permeability of formation, formation closure stress, type of optimization desired for particle geometry placed perforation below such as optimized length of solid fracture maintenance material packaged in fracture, optimized height of sand control package, optimized fracture package and / or conductivity of sand control package and its combinations. The fracture fluid, to be used with the composite, exhibits high viscosity, in order to be able to carry effective volumes of one or more solid hydraulic fracture maintenance materials. It can include any aqueous gels and hydrocarbon gels.
    [0070] [00070] The composite can still be advantageously used in carrier fluids of foamed gas and liquefied gas, such as liquid CO2, CO2 / N2, and foamed N2 in CO2-based systems. In this sense, fracture work characteristics based on liquid CO2, such as amounts of solid material, sizes of solid fracture maintenance material, and pumping methodologies, using porous ceramic materials of relatively light weight can be the same as used for conventional solid hydraulic fracture maintenance materials.
    [0071] [00071] Also, a gravel package operation can be performed on a well borehole that penetrates an underground formation to prevent or substantially reduce the production of formation particles in the well bore from the formation during production of formation fluids. The underground formation can be completed in order to be in communication with the interior of the well drilling through any process known in the art, for example, through drilling in coated well drilling, and / or through an open drilling section . A screen assembly as is known in the art can be placed or otherwise arranged within a well bore so that at least a portion of the screen assembly is disposed adjacent to the underground formation. A paste including the composite and a carrier fluid can then be introduced into the well bore and placed adjacent to the underground formation through circulation or another appropriate process in order to form a fluid-permeable package in an annular area between the outside of the screen and the interior of the well bore which is able to reduce or substantially prevent the formation of particles from underground formation in the well bore during production of fluids from the formation, while at the same time allowing the passage of formation fluids from the formation underground through a screen in the drilling of a well. It is possible that the paste may contain all or only a portion of the composite; the balance of the slurry may be another material, such as conventional gravel packet particles.
    [0072] [00072] As an alternative to using a screen, the composite can be used in any process in which a package of particulate material is formed within a well bore that is permeable to fluids produced from the well bore, such as such as oil, gas, or water, but which substantially prevents or reduces production of formation materials, such as formation sand, from formation in well drilling. Such processes may or may not use a gravel pack screen, can be introduced into a well bore at pressures below, at or above the fracture pressure of the formation, such as a weak pack, and / or can be used in conjunction with resins such as sand consolidating resins if desired.
    [0073] [00073] The composite is typically strong enough to be used as a solid hydraulic fracture maintenance material during high pressure hydraulic fracture operation. They can still be used in conjunction with other well treatment agents including non-porous solid fracture maintenance materials, such as sand.
    [0074] [00074] When used in fracture, the fluid may or may not contain a solid hydraulic fracture maintenance material.
    [0075] [00075] In another embodiment, the calcined porous metal oxide of the composite can be reactivated or refilled with the well treatment agent after at least a portion of the well treatment agent has been depleted. Such processes are shown in US 7,686,081 and US 2010/0175875, both of which are incorporated herein by reference.
    [0076] [00076] In this procedure, an initial load of the composite can be injected into the well drilling in a conventional process, whether for fracture or for a gravel package. Such conventional processes include vehicle treatment, continuous injection, or high pressure pumping, for example. The drilling matrix below formed within formation after the initial loading is comprised of a well treatment agent on a water-insoluble adsorbent as part of the sand matrix.
    [0077] [00077] For gravel packaging in a sand control process, the composite is placed adjacent to an underground formation to form a fluid permeable matrix capable of reducing or substantially preventing the formation of particles from underground formation during drilling well while allowing the passage of formation fluids from the underground formation in the well drilling.
    [0078] [00078] When a screen device is used, the screen device is placed in the well bore before injection of the composite. The mixture is injected so that it packs around the outside of the screen device to provide a fluid-permeable matrix around the screen device that is capable of reducing or substantially preventing the passage of formation particles from the underground formation in the well drilling while at the same time allowing the passage of formation fluids from the underground formation in the well drilling. In addition, the screen itself can be packaged with the well treatment composite.
    [0079] [00079] Additional amount of fluid containing well treatment agent can be injected into the formation at any time after the initial load of well treatment agent in the composite has at least partially been exhausted. Typically, the additional well treatment agent is introduced when the well treatment agent adsorbed on the adsorbent or within interstitial spaces of the composite has been substantially depleted and the level of performance of the well treatment agent in the composite has become unacceptable. .
    [0080] [00080] The injection of additional well treatment agent can be carried out in the same way that the initial composite was loaded into the well drilling, and can be carried out in any conventional fluid injection process in a well drilling of a well. oil or gas well, as mentioned above. The fluid that is injected will typically be comprised of the desired well-treating agent (s) in a solution that still comprises a solvent. The relative amounts of the solvent and agent for treatment of the solution to be injected into the well drilling will of course vary depending on the agent and solvent involved, but will typically be from a solvent to agent to treatment ratio in the range of about 10:90 to about 95: 5 by weight. The solvent in one embodiment is xylene, toluene, or a heavy aromatic distillate or a mixture thereof. When a mixture of all xylene, toluene, and heavy aromatic distillate is used, the relative amounts of each solvent component may vary, but will typically be in varying weight ratios (xylene: toluene: aromatic distillate) such as 10:70:20 , 20:70:10, 70:20:10 or 20:10:70. In another embodiment, the solvent may be water (for water-soluble well treatment agents).
    [0081] [00081] After the injection stage is performed, the well drilling is pressurized for a time and under sufficient conditions to reactivate the orifice matrix below in the formation. This pressurization of material in well drilling and formation fracture is commonly referred to as a "compression". Reactivation of the agent for treatment orifice below can occur through the squeezing process as much as the activity of the agent for treatment in the matrix at the site is increased over the activity of agent for treatment of the matrix just before injection of solution. The determination of whether the activity of agent for treatment increased in relation to the activity of that agent just before injection of the solution and end of compression can be done through conventional residual analysis and comparison of the same before and after squeezing, and conventional analysis of parameters well physicists, for example, the rate of well production and well pressure.
    [0082] [00082] The pressure at which the well is pressurized in the squeezing process will typically be a pressure below the fracture pressure and, when applicable, below the pressure that can cause the gravel pack to break. In one embodiment of the invention, the pressure is in the range of about 3.5 (500 psia) to about 103.5 MPa (15000 psia). The duration for which the pressure condition is applied to the well will vary, depending on the case of fracture, but will typically be in the range of about 2 to about 10 hours.
    [0083] [00083] In another embodiment, the well treatment composite can be used to pre-package a screen for use in wells packed with gravel. In this embodiment, the composite is preferably placed as close to the equilibrium point as possible in order to ensure the continuous release of the agent for treating the well throughout the production stream. In this way, the well treatment composite can be used as a preventive measure by stopping precipitation and depositing the well treatment agent before it starts. Such alternatives are desirable, for example, when there is a need to increase the amount of the solid well treatment agent that can be placed in wells packed with gravel there the amount of solid hydraulic fracture maintenance material or gravel placed in the well is at a minimum. In addition, well treatment composites on prepackaged screens can be used to increase the amount of solid substrate exposed during sand control. When used in sand control, screens pre-packaged with the composite for treatment of wells can reduce intervention costs for remediation and also increase the efficiency of operation. Preferably, however, the mesh used is of a size to reduce clogging through the formation of fine migration.
    [0084] [00084] The following examples are illustrative of some of the embodiments of the present invention. Other realizations within the scope of the present claims will be apparent to those skilled in the art from consideration of the description shown here. It is intended that the descriptive report, along with the examples, should only be considered exemplary, with the scope and spirit of the invention being indicated by the claims that follow.
    [0085] [00085] All percentages shown in the Examples are given in terms of units by weight unless otherwise stated. EXAMPLES
    [0086] [00086] Example 1. According to the procedure shown in US 4,013,587, alumina spheres were prepared by hydrolysis of aluminum alkoxide. The resulting spheres were then dried to remove water. The dried aluminum was then dispersed in an oil at about 90 ° C. Gel particles were formed.
    [0087] [00087] Spherical water-insoluble particles of more than 95% alumina were recovered as Sample A. The spherical alumina beads consisted of bohemite (uncalcined) alumina having a diameter of 1 mm, a pore volume of 0.5 cm3 / g and a surface area of 216 m2 / g.
    [0088] [00088] A portion of Sample A was calcined at 1200 ° C for 2 hours to yield spherical beads 1 mm in diameter (Sample B) composed of alpha / delta theta alumina and having a pore volume of 0.08 cm3 / g a surface area of 3 m3 / g.
    [0089] [00089] A portion of Sample A was calcined at 1400 ° C for 2 hours to yield spherical beads 1 mm in diameter (Sample C) composed of alpha alumina and having a pore volume of 0.03 cm3 / g and a surface area of 4 m2 / g.
    [0090] [00090] Example 2. Each Sample A, Sample B and Sample C were added in different percentages of cargo weight to commercial light weight ceramic hydraulic fracture maintenance material, commercially available as CARBO LITE from Carbo Ceramics Inc. of Dallas , Texas, and crushing was determined according to ISO13503-2. Measurement of properties of hydraulic fracture maintenance solid materials used in hydraulic fracture and gravel packing operations. The results are shown in Table I below where the Comparative Sample is a 10/50 mesh diatomaceous earth (Celite MP-79):
    [0091] [00091] The results indicate that sample A not calcined has resistance comparable to the diatomaceous earth of the Comparative Sample, while Sample B calcined and Sample C had the resistance of solid material of maintenance of hydraulic fracture in which even after the addition of 10% by weight of Sample B or Sample C the crushing resistance of hydraulic fracture maintenance solid particle mixtures, even at 69.0 MPa (10000 psi), was not changed.
    [0092] [00092] Example 3. Amino acid (methylene phosphonic) (ATMP) scale inhibitor, commercially available as Dequest 2000 from ThermPhos International BV was adsorbed on each of samples A, B and C to yield samples FBG-90706-4A, FBG-90706- 4B and FBG-907064C, respectively. These samples were prepared by first water adsorption on the samples to determine how much water can be adsorbed. Water was added to the sample until the sample appears moist. Sample A was verified to adsorb 0.698 g of H2O / g of sample, Sample B adsorbed 0.362 g of H2O / g of sample, and Sample C adsorbed 0.415 g of H2O / g of sample. Next, Dequest 2000 was added to each sample. Due to the low adsorbance compared to diatomaceous earth, two additions were followed to prepare the samples. In the first addition to Sample A, only 0.32 g of Dequest 2000 / g of Sample A can be added. In the second addition, 0.25 g of Dequest 2000 / g of Sample A can be added. This results in a product that contains about 22% active content. The process used to prepare the diatomaceous earth-based product shown in US 7,493,955 was adapted for these alumina samples. For Sample B, only 0.31 g of Dequest 2000 / g of Sample B can be added followed by 0.13 g of Dequest 2000 / g of Sample B in the second addition. This results in a product that contains about 18% active content. For Sample C, only 0.23 g of Dequest 2000 / g of Sample C can be added followed by 0.08 g of Dequest 2000 / g of Sample C in the second addition. This results in a product that contains about 13.5% active content. The properties of each of these samples are shown in Table II below:
    [0093] [00093] Example 4. The elution characteristics of the solid composites of Example 3 were determined by packaging Ottawa sand of 20-40 mesh and solid inhibitor (2% by weight of sand) in a 35 cm stainless steel column. length (internal diameter = 1.08 cm). The pore volume was approximately 12 ml. The column was eluted with synthetic brine (0.025 mol / L) of CaCl2, 0.015 mol / L of NaHCO3, 1 mol / L of NaCl, sprayed with 100% CO2) at 60 ° C with a flow rate of 120 mL / hour . The synthetic brine was saturated with calcite to simulate typical brine brine in the formation. The effluent solution was collected and analyzed for phosphorus and Ca concentration to obtain an inhibitor release profile. The results are shown in FIG. 1A and FIG. 1B. The minimum effective concentration for scaling inhibition was 0.1 ppm.
    [0094] [00094] Example 5. Five alumina samples labeled 23A, 23B, 23C, 23D and 23E were prepared. 23-A was the same as Sample A (1 mm alumina pearl, not calcined); 23-B was the same as Sample B (1 mm alumina beads calcined at 1200 ° C for 2 hours) and 23-C was the same as Sample C (1 mm alumina beads calcined at 1400 ° C for 2 hours) ). Samples 23D and 23E were prepared using the same protocols as Sample B and Sample C, respectively, except that the diameter of the spherical beads was adjusted to 0.8 mm. Each of 23A, 23B, 23C, 23D and 23E was heated to 107.2 ° C and cooled to room temperature in a desiccator before adding the ATMP solution. A 55 wt% ATMP solution was prepared. Three additions were made for each sample and the amount that was able to be adsorbed is shown in Table III below:
    [0095] [00095] The results shown in Table III are in contrast to 22.1% for Sample A, 18.1% for Sample B and 13.5% for Sample C.
    [0096] [00096] Example 6. Elution of Samples 22B, 23C, 23D, 23E and the Comparative Sample of Example 2 was performed as shown through the process in Example 4 with 2% of the particles by weight of the sand in the column. The results are shown in FIG. 2. The results are similar to those illustrated in FIG. 1A and FIG. 1B. Since there is commercial interest in using a higher percentage of particles in a package of solid hydraulic fracture maintenance material, elution studies were performed on the samples in 50% of the particles in the sand package and the results are shown in FIG . 3. FIG. 3 indicates a much slower release and a longer period of effective inhibition.
    [0097] [00097] Example 7. Four samples were prepared in two different sizes (0.8 mm and 1.0 mm in diameter before calcination) according to the procedure shown in Example 1. The four samples were labeled as CO10118 (0, 8 mm), CO10118 (1 mm), CO10524 (0.8 mm) and CO10593 (1 mm). Sample CO10118, after calcination, had a size of 25 mesh (0.71 mm) and a surface area of 1 m2 / g; sample CO10118, after calcination, had a size of 30 mesh (0.59 mm) and a surface area of less than 1 m2 / g. Sample CO10524, after calcination, had a size of 30 mesh (0.59 mm) and a surface area of 5.6 m2 / g and sample CO10593, after calcination, had a size of 20 mesh (0.84 mm) and an area surface area of 7.3 m2 / g. Crush analyzes were conducted on each of the samples as well as on ECONOPROP, a solid commercial hydraulic fracture maintenance material available from Carbo Ceramics Inc. In addition, two other samples labeled APA 1.0 / 3C 12853 of 25 mesh (surface area of 3, 1 m2 / g) and APA0.8 / 3C 12852 of 30 mesh were also prepared. The crushing data on these are shown in Table 4. The crushing data for each sample was generated using an extended rainy season process to load the solid hydraulic fracture maintenance material into the API crushing cell. The results are shown in Table IV below:
    [0098] [00098] Example 8. Amino trimethylene phosphonic acid (ATMP) scale inhibitor, commercially available as Dequest 2000 from ThermPhos International BV was adsorbed on the four samples of Example 7 and the resulting materials were labeled FBG-100824A, FBG-100824B, FBG- 100824C and FBG-100824D, respectively. The procedure for preparing these samples is shown above in Example 3. The properties for each of the samples are shown in Table V below: Table V
    [0099] [00099] Example 9. The elution of each of the samples of Example 8 was carried out according to the procedures shown in Examples 4 and 6 with 50% of the particles by weight of the sand in the column. The results are shown in FIG. 4A and FIG. 4B and are compared to the results of 2% load of the composite exemplified in US 7,493,955. The results are similar to those of Example 6 and show that the amount of composite can be cut with the amount of solid hydraulic fracture maintenance material depending on the amount of water produced from the well and how much protection time is desired. As illustrated, 2% of particles in the sand and 50% of particles in the sand can be used for the same purpose.
    [0100] [000100] From the foregoing, it will be noted that numerous variations and modifications can be made without departing from the true spirit and scope of the new concepts of the invention.
    权利要求:
    Claims (18)
    [0001]
    Composite for well treatment, characterized by the fact that it comprises: a well treatment agent, and calcined porous metal oxide, the porosity and permeability of the calcined porous metal oxide being such that the well treatment agent is adsorbed on the calcined porous metal oxide or absorbed in the porous metal oxide interstitial spaces, and and still: (a) the surface area of the calcined porous metal oxide is between 1 m2 / g and 10 m2 / g; (b) the diameter of the calcined porous metal oxide is between 0.1 and 3 mm; and (c) the pore volume of the calcined porous metal oxide is between 0.01 and 0.10 g / cm3.
    [0002]
    Well treatment composite according to claim 1, characterized in that it contains between 1 and 50 weight percent of the well treatment agent.
    [0003]
    Composite for treatment of wells, according to claim 1, characterized by the fact that the porous metal oxide constitutes an adsorbent to the agent for treatment of wells, and the adsorbent also contains silica.
    [0004]
    Well treatment composite according to claim 1, characterized in that the well treatment agent is selected from the group consisting of fouling inhibitors, corrosion inhibitors, paraffin inhibitors, salt inhibitors, hydrate inhibitors gas, asphaltene inhibitors, oxygen scavengers, biocides, foaming agent, emulsion breakers, and surfactants, and mixtures thereof.
    [0005]
    Well treatment composite according to claim 4, characterized in that the well treatment agent is a scale inhibitor, a corrosion inhibitor, a paraffin inhibitor, a salt inhibitor, a hydrate inhibitor gas, an asphaltene inhibitor, or a mixture of these.
    [0006]
    Well treatment composite according to claim 5, characterized by the fact that the calcined porous metal oxide is alumina.
    [0007]
    Well treatment composite according to claim 1, characterized by the fact that the porous metal oxide is alumina.
    [0008]
    Well treatment composite according to claim 7, characterized in that the calcined porous alumina is alpha alumina / delta theta alumina or alpha alumina.
    [0009]
    Well treatment composite according to claim 1, characterized by the fact that the well treatment agent is soluble in water.
    [0010]
    Well treatment composite according to claim 1, characterized by the fact that the well treatment agent is soluble in hydrocarbons.
    [0011]
    Well treatment composite according to claim 1, characterized by the fact that the well treatment agent is soluble in water or soluble in hydrocarbon, and that it still contains between 1 to 50 weight percent of the agent for treatment of well pit.
    [0012]
    Composite for treatment of wells, according to claim 11, characterized by the fact that the alumina was calcined at temperatures above or equal to 1200 ° C.
    [0013]
    Composite for treatment of wells, according to claim 12, characterized by the fact that the alumina was calcined at temperatures above or equal to 1400 ° C.
    [0014]
    Composite for treatment of wells, according to claim 13, characterized by the fact that calcined porous alumina constitutes an adsorbent for the agent for treatment of wells, and the adsorbent also contains silica.
    [0015]
    Composite for treatment of wells, according to claim 12, characterized by the fact that: (a) the surface area of the calcined porous metal oxide is between 1 m2 / g and 10 m2 / g; (b) the diameter of the calcined porous metal oxide is comprised between 0.1 and 3 mm; (c) the pore volume of the calcined porous metal oxide is comprised between 0.01 and 0.10 cm3 / g; (d) the apparent density of the composite is comprised between 1.2 and 2.4 g / cm3 (75 and 150 lb / ft3); and (e) the density of the well treatment composite is less than or equal to 3.75g / cm3.
    [0016]
    Well treatment composition, characterized by the fact that it comprises the well treatment composite, as defined in claim 1, and at least one solid hydraulic fracture maintenance material, the said well treatment composite containing between 1 and 50 percent by weight of the well treatment agent.
    [0017]
    Well treatment composition according to claim 16, characterized by the fact that the porous metal oxide of the composite for well treatment is alumina.
    [0018]
    Composition for well treatment, characterized by the fact that it comprises the composite for well treatment, as defined in claim 11, and a solid hydraulic fracture maintenance material.
    类似技术:
    公开号 | 公开日 | 专利标题
    BR112013027230B1|2021-01-26|composite and composition for well treatment
    US10400159B2|2019-09-03|Composite comprising well treatment agent and/or a tracer adhered onto a calcined substrate of a metal oxide coated core and a method of using the same
    US9976070B2|2018-05-22|Method of using shaped compressed pellets in well treatment operations
    US10989040B2|2021-04-27|Method of using controlled release tracers
    US10822536B2|2020-11-03|Method of using a screen containing a composite for release of well treatment agent into a well
    US7493955B2|2009-02-24|Well treating compositions for slow release of treatment agents and methods of using the same
    US20130105157A1|2013-05-02|Hydraulic Fracturing Method
    CA2982915C|2021-06-15|Shaped compressed pellets for slow release of well treatment agents into a well and methods of using the same
    Gupta et al.2013|A chemical inhibitor-infused, high-strength proppant additive for reservoir flow assurance against scale deposition in wells with high intervention costs
    US20200148943A1|2020-05-14|Nanoparticle-based stimulation fluid and methods of use in subterranean formations
    同族专利:
    公开号 | 公开日
    US9029300B2|2015-05-12|
    BR112013027230A2|2016-12-27|
    MX366177B|2019-07-01|
    RU2600116C2|2016-10-20|
    US20150232741A1|2015-08-20|
    EP2702116B1|2020-03-25|
    EP2702116A1|2014-03-05|
    MX2013012367A|2014-02-03|
    CA2831800C|2016-07-12|
    CO6791604A2|2013-11-14|
    US20120273197A1|2012-11-01|
    CA2831800A1|2012-11-01|
    AR086048A1|2013-11-13|
    AU2012249983A1|2013-10-24|
    US9574130B2|2017-02-21|
    WO2012148819A1|2012-11-01|
    SG194642A1|2013-12-30|
    DK2702116T3|2020-06-08|
    CN103492526A|2014-01-01|
    RU2013152253A|2015-06-10|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    FR2299911B1|1975-02-04|1980-07-18|Kali Chemie Ag|
    US4390456A|1979-08-08|1983-06-28|W. R. Grace & Co.|Spheroidal alumina particles and catalysts employing the particles as a support|
    US4522731A|1982-10-28|1985-06-11|Dresser Industries, Inc.|Hydraulic fracturing propping agent|
    GB9503949D0|1995-02-28|1995-04-19|Atomic Energy Authority Uk|Oil well treatment|
    GB9611422D0|1996-05-31|1996-08-07|Bp Exploration Operating|Coated scale inhibitors|
    GB0028264D0|2000-11-20|2001-01-03|Norske Stats Oljeselskap|Well treatment|
    GB0028269D0|2000-11-20|2001-01-03|Norske Stats Oljeselskap|Well treatment|
    US7140438B2|2003-08-14|2006-11-28|Halliburton Energy Services, Inc.|Orthoester compositions and methods of use in subterranean applications|
    US20080287324A1|2002-03-01|2008-11-20|Cesi Chemical, Inc., A Flotek Company|Process for well cleaning|
    US7426961B2|2002-09-03|2008-09-23|Bj Services Company|Method of treating subterranean formations with porous particulate materials|
    US7135231B1|2003-07-01|2006-11-14|Fairmont Minerals, Ltd.|Process for incremental coating of proppants for hydraulic fracturing and proppants produced therefrom|
    US7871702B2|2003-07-30|2011-01-18|Halliburton Energy Services, Inc.|Particulates comprising silica and alumina, and methods of utilizing these particulates in subterranean applications|
    US20050028976A1|2003-08-05|2005-02-10|Nguyen Philip D.|Compositions and methods for controlling the release of chemicals placed on particulates|
    US20060065396A1|2004-08-13|2006-03-30|Dawson Jeffrey C|Compositions containing water control treatments and formation damage control additives, and methods for their use|
    US7491682B2|2004-12-15|2009-02-17|Bj Services Company|Method of inhibiting or controlling formation of inorganic scales|
    US8012533B2|2005-02-04|2011-09-06|Oxane Materials, Inc.|Composition and method for making a proppant|
    BRPI0606548A2|2005-02-04|2009-06-30|Oxane Materials Inc|proppant, method for producing a proppant, proppant formulation, method for filling and supporting open fractions of underground formations, and method for treating a producing underground zone|
    JP2008531459A|2005-03-01|2008-08-14|カーボ、サラミクス、インク|Method for producing sintered particles from a slurry of an alumina-containing raw material|
    US20060223713A1|2005-04-05|2006-10-05|Bj Services Company|Method of completing a well with hydrate inhibitors|
    US20060272816A1|2005-06-02|2006-12-07|Willberg Dean M|Proppants Useful for Prevention of Scale Deposition|
    US7598209B2|2006-01-26|2009-10-06|Bj Services Company|Porous composites containing hydrocarbon-soluble well treatment agents and methods for using the same|
    US8562900B2|2006-09-01|2013-10-22|Imerys|Method of manufacturing and using rod-shaped proppants and anti-flowback additives|
    US8183184B2|2006-09-05|2012-05-22|University Of Kansas|Polyelectrolyte complexes for oil and gas applications|
    US7490667B2|2006-10-02|2009-02-17|Fairmount Minerals, Inc.|Proppants with soluble composite coatings|
    RU2344155C2|2006-12-27|2009-01-20|Шлюмбергер Текнолоджи Б.В.|Proppant on basis of aluminium silicates, method of its preparation and method of its application|
    US7918281B2|2007-03-06|2011-04-05|Baker Hughes Incorporated|Method of treating flow conduits and vessels with foamed composition|
    US20080217012A1|2007-03-08|2008-09-11|Bj Services Company|Gelled emulsions and methods of using the same|
    US7737091B2|2007-08-28|2010-06-15|Imerys|Proppants and anti-flowback additives made from sillimanite minerals, methods of manufacture, and methods of use|
    EP2060613A1|2007-11-16|2009-05-20|BJ Services Company|Method of treating subterranean formations by in-situ hydrolysis of organic acid esters|
    US7968500B2|2008-06-25|2011-06-28|Baker Hughes Incorporated|Gas hydrate protection with heat producing two-component gas hydrate inhibitors|
    US7977283B2|2008-06-27|2011-07-12|Baker Hughes Incorporated|Method of minimizing or reducing salt deposits by use of a fluid containing a fructan and derivatives thereof|
    US8336624B2|2008-10-30|2012-12-25|Baker Hughes Incorporated|Squeeze process for reactivation of well treatment fluids containing a water-insoluble adsorbent|
    US7686081B1|2008-10-30|2010-03-30|Bj Services Company|Squeeze process for reactivation of well treatment fluids containing diatomaceous earth|
    US9010430B2|2010-07-19|2015-04-21|Baker Hughes Incorporated|Method of using shaped compressed pellets in treating a well|
    US8664168B2|2011-03-30|2014-03-04|Baker Hughes Incorporated|Method of using composites in the treatment of wells|
    US9102860B2|2011-06-16|2015-08-11|Baker Hughes Incorporated|Method of inhibiting or controlling release of well treatment agent|CN108291135A|2015-04-20|2018-07-17|通用电气贝克休斯有限责任公司|For well inorganic agent to be released slowly into the compression spherolite of the forming in well and its application method|
    WO2018208587A1|2017-05-11|2018-11-15|Baker Hughes, A Ge Company, Llc|Method of using crosslinked well treatment agents for slow release into well|
    US9976070B2|2010-07-19|2018-05-22|Baker Hughes, A Ge Company, Llc|Method of using shaped compressed pellets in well treatment operations|
    US10822536B2|2010-07-19|2020-11-03|Baker Hughes, A Ge Company, Llc|Method of using a screen containing a composite for release of well treatment agent into a well|
    US10077395B2|2011-03-11|2018-09-18|Carbo Ceramics Inc.|Proppant particles formed from slurry droplets and methods of use|
    BR112014012122A8|2011-11-22|2017-06-20|Baker Hughes Inc|method of use of controlled release trackers|
    US9580642B2|2011-11-22|2017-02-28|Baker Hughes Incorporated|Method for improving isolation of flow to completed perforated intervals|
    MX2015001526A|2012-08-01|2015-04-08|Oxane Materials Inc|Synthetic proppants and monodispersed proppants and methods of making the same.|
    US20140190692A1|2013-01-04|2014-07-10|Independence Oilfield Chemicals|Production-treating chemicals added to polymer slurries used in treatment of oil and gas wells|
    CA2849415C|2013-04-24|2017-02-28|Robert D. Skala|Methods for fracturing subterranean formations|
    NO340689B1|2013-06-24|2017-05-29|Inst Energiteknik|tracers|
    US10081762B2|2013-09-17|2018-09-25|Baker Hughes, A Ge Company, Llc|Well treatment methods and fluids containing synthetic polymer|
    US10822917B2|2013-09-17|2020-11-03|Baker Hughes, A Ge Company, Llc|Method of cementing a well using delayed hydratable polymeric viscosifying agents|
    US10844270B2|2013-09-17|2020-11-24|Baker Hughes, A Ge Company, Llc|Method of enhancing stability of cement slurries in well cementing operations|
    GB2520019A|2013-11-06|2015-05-13|Statoil Petroleum As|Functionalized proppants|
    CN103773356B|2014-01-21|2016-11-16|成都新柯力化工科技有限公司|A kind of shale gas exploitation particulate material and preparation method thereof|
    US10287865B2|2014-05-19|2019-05-14|Baker Hughes, A Ge Company, Llc|Use of an acid soluble or degradable solid particulate and an acid liberating or acid generating composite in the stimulation of a subterranean formation|
    EA035175B1|2014-06-30|2020-05-12|Шлюмберже Текнолоджи Б.В.|Method for producing a composite proppant|
    MX2017000875A|2014-07-23|2017-05-04|Baker Hughes Inc|Composite comprising well treatment agent and/or a tracer adhered onto a calcined substrate of a metal oxide coated core and a method of using the same.|
    US9656237B2|2014-07-31|2017-05-23|Baker Hughes Incorporated|Method of scavenging hydrogen sulfide and mercaptans using well treatment composites|
    EA034457B1|2014-07-31|2020-02-11|Карбо Керамикс, Инк.|Methods and systems for infusing porous ceramic proppant with a chemical treatment agent|
    US10280737B2|2015-06-15|2019-05-07|Baker Hughes, A Ge Company, Llc|Methods of using carbon quantum dots to enhance productivity of fluids from wells|
    EP3317366A1|2015-06-30|2018-05-09|Dow Global Technologies LLC|Coating for controlled release|
    CN105152367A|2015-10-10|2015-12-16|无棣华信石油技术服务有限公司|Environment-friendly oilfield reinjection water corrosion and scale inhibitor and preparation method thereof|
    US10577534B2|2016-04-08|2020-03-03|Baker Hughes, A Ge Company, Llc|Well treatment material for slow release of biocide|
    US10641083B2|2016-06-02|2020-05-05|Baker Hughes, A Ge Company, Llc|Method of monitoring fluid flow from a reservoir using well treatment agents|
    EP3440150B1|2016-06-03|2019-09-04|Tomson Technologies|Nanoparticle carrier platform and methods for controlled release of subterranean well treatment additives|
    US10413966B2|2016-06-20|2019-09-17|Baker Hughes, A Ge Company, Llc|Nanoparticles having magnetic core encapsulated by carbon shell and composites of the same|
    US10400152B2|2016-08-19|2019-09-03|Baker Hughes, A Ge Company, Llc|Liquid loaded powders made from hybrid calcium carbonate for oil and gas drilling fluids|
    WO2019013799A1|2017-07-13|2019-01-17|Baker Hughes, A Ge Company, Llc|Delivery system for oil-soluble well treatment agents and methods of using the same|
    EP3704206A1|2017-11-03|2020-09-09|Baker Hughes Holdings Llc|Treatment methods using aqueous fluids containing oil-soluble treatment agents|
    US20210340432A1|2018-07-30|2021-11-04|Baker Hughes Holdings Llc|Methods of Using Delayed Release Well Treatment Composititions|
    US11028309B2|2019-02-08|2021-06-08|Baker Hughes Oilfield Operations Llc|Method of using resin coated sized particulates as spacer fluid|
    CN110157401A|2019-05-06|2019-08-23|中国石油天然气股份有限公司|A kind of preparation method of controllable long-acting slow-release scale inhibition agent capsules|
    CN110643345B|2019-10-16|2021-12-14|北京弘毅恩泽能源技术有限公司|Adsorption slow-release acid system for acid fracturing and preparation method thereof|
    US10961444B1|2019-11-01|2021-03-30|Baker Hughes Oilfield Operations Llc|Method of using coated composites containing delayed release agent in a well treatment operation|
    法律状态:
    2018-04-03| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|
    2019-07-23| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|
    2020-08-04| B07A| Technical examination (opinion): publication of technical examination (opinion)|
    2020-12-01| B09A| Decision: intention to grant|
    2021-01-26| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 20/04/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US13/094,186|2011-04-26|
    US13/094,186|US9029300B2|2011-04-26|2011-04-26|Composites for controlled release of well treatment agents|
    PCT/US2012/034507|WO2012148819A1|2011-04-26|2012-04-20|Composites for controlled release of well treatment agents|
    [返回顶部]