EP2959092A1 - Procédé pour améliorer l'efficacité d'un fluide de forage - Google Patents

Procédé pour améliorer l'efficacité d'un fluide de forage

Info

Publication number
EP2959092A1
EP2959092A1 EP14754602.2A EP14754602A EP2959092A1 EP 2959092 A1 EP2959092 A1 EP 2959092A1 EP 14754602 A EP14754602 A EP 14754602A EP 2959092 A1 EP2959092 A1 EP 2959092A1
Authority
EP
European Patent Office
Prior art keywords
drill
fluid
gas generating
foamed
tool
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP14754602.2A
Other languages
German (de)
English (en)
Other versions
EP2959092A4 (fr
Inventor
Philip D. Nguyen
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Halliburton Energy Services Inc
Original Assignee
Halliburton Energy Services Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Publication of EP2959092A1 publication Critical patent/EP2959092A1/fr
Publication of EP2959092A4 publication Critical patent/EP2959092A4/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/14—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor using liquids and gases, e.g. foams
    • 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
    • C09K8/02—Well-drilling compositions
    • C09K8/38—Gaseous or foamed well-drilling compositions
    • 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
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
    • C09K8/518—Foams
    • 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
    • C09K8/94—Foams
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/06—Arrangements for treating drilling fluids outside the borehole

Definitions

  • the present invention relates to methods of enhancing drilling fluid performance. More particularly, the present invention relates to enhancing drilling fluid performance where foam is used as at least part of the drilling fluid.
  • Hydrocarbons such as oil and gas
  • Such formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect.
  • a well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
  • a drill bit is attached to a series of pipe sections or coiled drilling tubing referred to as the drill string.
  • the drill string terminates in a drill tool, which cuts a borehole through the different formations.
  • the drill string is gradually lengthened as the drill tool cuts the borehole.
  • drilling in the borehole is also utilized in well completion and production operations, such as drilling out packers utilized during well casing operations and workover operations.
  • drilling fluids are used for a variety of other purposes.
  • the drilling fluid also helps stabilize uncased portions of the wellbore and prevents it from caving in. Large quantities of cuttings are generated during drilling. As it is re-circulated back up the wellbore, the drilling fluid also carries cuttings away from the drill tool and out of the wellbore. Also when rotary drill tools or drill bits are used, a tremendous amount of heat can be generated as the drill string is rotated and the bit cuts through the earth.
  • the drilling fluid serves to lubricate and cool the drill bit.
  • drilling fluids have most commonly been high-density dispersions of fine, inorganic solids, such as clay and barite, in an aqueous liquid or hydrocarbon liquid.
  • These drilling fluids have traditionally been called drilling mud and the drilling has been conducted in an overbalanced condition; that is, the hydrostatic pressure of drilling fluid in the wellbore exceeds the pressure of hydrocarbons in the formation. Hydrocarbons, therefore, are prevented from flowing into the wellbore. This avoids the risk that the well will blow-out and damage the environment and drilling equipment or injure those working on the drilling rig.
  • drilling fluid can flow from the wellbore into the formation. That flow of fluid at relatively low levels is referred to as seepage and, at higher levels, as lost circulation. Seepage, and especially lost circulation, in turn may have several deleterious and costly effects.
  • any drilling fluid that flows into the formation must be replaced in order to maintain circulation of fluid through the well. The amount and cost of drilling fluid required to drill the well, therefore, is increased.
  • the problems associated with seepage and lost circulation may be addressed by adjusting the density of the drilling mud.
  • the density of the drilling mud may be controlled by the amount of solids added and, therefore, adjusted to balance the hydrostatic pressures at the interface between the wellbore and the formation. Seepage and lost circulation and their attendant problems also may be addressed by the formation of a filter cake on the wall of the wellbore or by the addition of filtration control and seepage control additives designed to physically impede the flow of fluid into the wellbore.
  • drilling mud is suitable for use in a wide variety of hydrocarbon bearing formations
  • the hydrostatic pressure of hydrocarbons in the formation is relatively low and many drilling muds are simply too heavy for low pressure formations. They can significantly overbalance the well, allowing excessive amounts of drilling fluid to flow into the formation.
  • the problems caused by seepage and lost circulation are exacerbated when a low pressure formation is also relatively fragile, such as fractured limestone formations. Fragile formations may be excessively fractured by the hydrostatic pressure of drilling fluid flowing into the formation and carry even more materials into the formation that will diminish its permeability. Seepage and lost circulation materials, in particular, if they are carried into the formation, can cause extensive damage to the formation.
  • drill-in fluids are specially designed to minimize formation damage when drilling into reservoir sections.
  • Drill-in fluids may be an aqueous brine containing only selected solids of appropriate particle size ranges (salt crystals or calcium carbonate) and polymers.
  • additives in drill-in fluids have been limited to ones essential for filtration control and cuttings carrying. Accordingly, these drill-in fluids have included a bridging agent designed to form a filter cake, which is external to the formation and which can easily be removed during the completion phase.
  • Such drill-in fluids may still be too heavy for use in extremely low-pressure, fragile formations without substantial losses.
  • Lower densities have been achieved by using foamed drill-in fluids.
  • They typically comprise a surfactant solution with gas dispersed therein.
  • the surfactant acts to stabilize the gas dispersion.
  • aqueous systems are preferred, and they typically include a polymer to improve the rheological and thixotropic properties of the foam.
  • foamed drill-in fluids perform quite well in drilling operations and offer several advantages over traditional suspended solids drilling fluids.
  • the density of the foam may be controlled relatively easily by adjusting the gas injected into the foam.
  • the ability of foamed drill-in fluids to carry cuttings away from a drilling bit is much greater than that of liquid drilling fluids. More effective removal of cuttings allows drilling to proceed at a faster pace, thereby reducing the time and expense of drilling.
  • foamed drill-in fluids can effectively prevent damage to even highly fragile, highly permeable formations.
  • Foamed drill-in fluids are prepared by mixing a liquid phase, such as a polymer- surfactant solution, and a gas phase, such as nitrogen. Typically, this has been done by high velocity mixing of the phases or by injecting gas into the liquid phase through a small orifice. Most commonly, the foam is generated at the surface and then pumped into the wellbore. It also has been suggested that drill-in fluids may be foamed by pumping separate liquid and gas streams through a drill string to a downhole foam generator.
  • foamed drill-in fluids require a source of gas such as nitrogen and various additional equipment that are not needed in conventional liquid circulation systems. For example, if liquid nitrogen is used, special tanks and equipment for cryogenically storing and handling the liquid nitrogen are required. Foam circulation systems also may include compressors, storage tanks, air pumps, foam generators, and other equipment beyond that commonly employed for circulating liquids. Moreover, unlike many other drilling fluids which are hydraulic, foamed drill-in fluids are pneumatic. Special pneumatic pumps and control heads may have to be used to pump or otherwise control the foam in the wellbore. Thus, systems for preparing and circulating foamed drill-in fluids are relatively costly and require more maintenance, control, and logistical support than those required for more traditional suspended solids drilling fluids.
  • the present invention relates to methods of generating gas downhole during drilling operations so as to produce a foamed drill-in fluid downhole between the drill tool and the wellbore.
  • the present invention provides a method of drilling in a wellbore comprising the steps of providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; introducing the drill-in fluid downhole into a drill string connected to a drill tool wherein both the gas generating chemical and the encapsulated activator are admixed into the drill-in fluid prior to introduction into the drill string; and allowing the drill-in fluid to exit the drill tool where, upon exiting the drill tool, the encapsulated activator is de-capsulated sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid.
  • the present invention provides a method of drilling in a wellbore comprising the steps of providing a drill-in fluid consisting essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator; introducing the drill-in fluid downhole into a drill string connected to a drill tool wherein the aqueous fluid, the foaming agent, the foam stabilizer, the gas generating chemical and the encapsulated activator are all admixed into the drill-in fluid prior to introduction into the drill string; and allowing the drill-in fluid to exit the drill tool where, upon exiting the drill tool, the encapsulated activator is de-capsulated sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid.
  • the present invention provides improved methods of generating gas in and foaming a drill-in fluid upon the drill-in fluid's exiting the drill tool; that is, while the drill- in fluids are passing from the interior to the exterior of the drill tool and while the drill-in fluid is in the region between the drill tool and the borehole where drilling of the formation is occurring.
  • the drill-in fluid comprises an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator.
  • the drill-in fluid can comprise a water soluble viscosifier, a fluid loss control additive and a bridging agent.
  • the viscosifier, fluid loss control additive and bridging agent are optional and depend upon the specific application; however, it is a distinct advantage of the current invention that the drill-in fluid described herein will have a reduced need for fluid loss control additives, viscosifying agents and/or bridging agents. Accordingly, for many applications, the drill-in fluid will not contain these components and, indeed, the inventive drilling process will be carried out without the use of viscosifiers, fluid loss control additives and bridging agents other than as those functions are carried out by one or more of the aqueous fluid, foaming agent, foam stabilizer, gas generating chemical and an encapsulated activator as present in the foamed drilling fluid.
  • the drill-in fluid consists essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator. It should be understood that for the components of the drill-in fluid, the use of singular forms of "a,” “an” and “the” include plurals and thus encompass one or more of the listed components.
  • the aqueous fluid of the drill-in fluid can be any aqueous liquid capable of forming a solution with the other components of the drill-in fluid.
  • solution as used herein, encompasses dispersions, emulsions, or any other substantially homogeneous mixture, as well as true solutions.
  • the solvent preferably is either fresh water or an aqueous brine.
  • the aqueous liquid can make up from about 80 percent to about 98 percent of the drill-in fluid by weight.
  • the gas generating chemicals useful in accordance with this invention will react with the activator in aqueous solutions to generate a gas, which may be selected from the group consisting of carbon dioxide, oxygen, sulfur dioxide, nitrogen, nitrogen dioxide, ammonia, and mixtures thereof, or consisting of any subgroup of the foregoing.
  • gas generating chemicals that react to generate primarily carbon dioxide or nitrogen are preferred. While the gas generating chemicals will generally produce one primary gas, they can also produce one or more secondary gases. For example, those that primarily generate nitrogen can also generate small amounts of ammonia depending on the chemical structure of the gas generating chemical and the activator or activating agent.
  • additional ammonia, carbon dioxide (an acidic gas), and carbon monoxide may be produced.
  • one or more encapsulated activators are combined with the drill-in fluid containing one or more gas generating chemicals.
  • the encapsulated activator can have a pre-selected release time or temperature such that the activator becomes de-capsulated after a pre-selected amount of time in the drill-in fluid or after the drill-in fluid reaches a pre-selected temperature; however, it is preferred that the encapsulated activator have a release associated with the high shear conditions at the drill tool. Accordingly, in one embodiment, the encapsulation material releases or de-capsulates the activator when the drill-in fluid undergoes the shear conditions at the drill tool and/or in the region between the drill tool and borehole.
  • the conditions in these regions are what is known as high shear conditions and will be greater shear conditions than experienced by the drill-in fluid prior to entering the drill tool from the drill string.
  • the release or de-capsulation should be sufficient so that enough activator reacts with the gas generating chemical so as to generate gas sufficient to foam the drill-in fluid to a predetermined level or density. In this manner, the encapsulated activator can be released without relying on time or temperature release encapsulating means.
  • the gas generating chemicals will be a reducing agent and the encapsulated activator will be an oxidizing agent.
  • the gas generating chemical it is within the scope of the invention for the gas generating chemical to be the oxidizing agent and the encapsulated activator to be the reducing agent.
  • the compounds below are listed as either a gas generating chemical or as an encapsulated activator, it should be understood that this is how they will typically be utilized in the invention but they can serve as either as long as there is both a reducing agent and an oxidizing agent; that is, a reducing compound can serve as the encapsulated activator as long as an oxidizing agent serves as the gas generating chemical.
  • a solid compound will be chosen as the encapsulated activator.
  • Nitrogen gas generating chemicals which can be utilized in accordance with the methods of the present invention include, but are not limited to, compounds containing hydrazine or azo groups, for example, hydrazine, azodicarbonamide, azobis (isobutyronitrile), p-toluene sulfonyl hydrazide, p-toluene sulfonyl semicarbazide, carbohydrazide, p-p' oxybis (benzenesulfonylhydrazide) and mixtures thereof.
  • compounds containing hydrazine or azo groups for example, hydrazine, azodicarbonamide, azobis (isobutyronitrile), p-toluene sulfonyl hydrazide, p-toluene sulfonyl semicarbazide, carbohydrazide, p-p' oxybis (benzenesulfony
  • nitrogen gas generating chemicals which do not contain hydrazine or azo groups and which are also useful in the present invention include, but are not limited to, ammonium salts of organic or inorganic acids, hydroxylamine sulfate, carbamide and mixtures thereof. Of these, azodicarbonamide or carbohydrazide are preferred.
  • the generation of gas from the nitrogen gas generating chemicals depends on the structure of the gas generating chemicals.
  • the chemical contains an azo group containing two nitrogens connected by a double bond as in azodicarbonamide
  • the gas generation is caused either thermally or by reaction with alkaline reagents.
  • the reactions with the azocarbonamide generate ammonia gas and possibly carbon dioxide and release the doubly charged diimide group.
  • the diimide dianion being chemically unstable decomposes to nitrogen gas.
  • the gas generating chemicals containing hydrazide groups in which the two nitrogen atoms are connected by a single bond as well as connected to one or two hydrogens produce gas upon reaction with an oxidizing agent.
  • hydrazide materials containing two mutually single bonded nitrogens which in turn are also bonded to one or more hydrogens, need oxidizing agents for activation.
  • alkaline pH is generally required. Occasionally, additional chemicals may be needed to increase the rate of gas production.
  • Examples of delayed encapsulated activators suitable for use with nitrogen gas generating chemicals include, but are not limited to, alkaline materials such as carbonate, hydroxide and oxide salts of alkali and alkaline earth metals such as lithium, sodium, magnesium and calcium and oxidizing agents such as alkali and alkaline earth metal salts of peroxide, persulfate, perborate, hypochlorite, hypobromite, chlorite, chlorate, iodate, bromate, chloroaurate, arsenate, antimonite and molybdate anions.
  • alkaline materials such as carbonate, hydroxide and oxide salts of alkali and alkaline earth metals such as lithium, sodium, magnesium and calcium
  • oxidizing agents such as alkali and alkaline earth metal salts of peroxide, persulfate, perborate, hypochlorite, hypobromite, chlorite, chlorate, iodate, bromate, chloroaurate, arsenate, antimonit
  • oxidizing agents include ammonium persulfate, sodium persulfate, potassium persulfate, sodium chlorite, sodium chlorate, hydrogen peroxide, sodium perborate and sodium peroxy carbonate.
  • oxidizers which can be used in the present invention are disclosed in U.S. Pat. No. 5,962,808 issued to Landstrom on October 5, 1999.
  • sodium or ammonium persulfate and sodium chlorite are preferred.
  • the actual amounts of the alkaline material used in the well treating fluid should be sufficient to maintain the pH of the fluid between 10 and 14.
  • Carbon dioxide gas generating chemicals can be selected from the group consisting of organic acids and inorganic acids, and mixtures thereof.
  • Organic acids suitable for use as the gas generating chemical can be selected from the group consisting of carboxylic acids, acetic acids, acetyl salicylic acids, ascorbic acids, citric acids, lactic acids, tartaric acids, gluconic acids, phenyl glycolic acids, benzylic acids, malic acids, salicylic acids, formic acids, propionic acids, butyric acids, oleic acids, linoleic acids, linolenic acids, sorbic acids, benzoic acids, phenyl acetic acids, gallic acids, oxylacetic acids, valeric acids, palmitic acids, fatty acids, valproic acids, acrylic acids, and methacrylic acids, and mixtures thereof, or consisting of any subgroup of the foregoing.
  • Inorganic acids suitable for use as the gas generating chemical can be selected from the group consisting of hydrochloric acids, sulfuric acids, nitric acids, sulfonitric acids, polyphosphoric acids, chlorosulfuric acids, and boric acids, and mixtures thereof, or consisting of any subgroup of the foregoing.
  • the second foam generating agent is 2-hydroxy-l,2,3-propanetricarboxylic acid, citric acid, or mixtures thereof.
  • Encapsulated activators suitable for use with carbon dioxide gas generating chemicals include, but are not limited to, acid and neutral salts of alkali metals and alkaline earth metals, and mixtures thereof, or consisting of any subgroup of the foregoing.
  • the encapsulated activator can be selected from the group consisting of sodium bicarbonate, potassium bicarbonate, calcium bicarbonate, barium bicarbonate, and lithium bicarbonate, and mixtures thereof, or consisting of any subgroup of the foregoing.
  • the activators can be encapsulated with various materials which delay their reaction with the gas generating chemical or chemicals used.
  • Solid activators can be encapsulated by spray coating a variety of materials thereon.
  • coating materials include, but are not limited to, waxes, drying oils such as tung oil and linseed oil, polyurethanes and cross-linked partially hydrolyzed polyacrylics.
  • an additional undercoat of polymeric materials such as styrene butadiene can be deposited on the solid activator particles prior to depositing the slow releasing polymeric coating.
  • the encapsulating material is chosen so that sufficient release of the activator under the shear conditions at and around the drill tool will be achieved to provide release of sufficient gas to adequately foam the drill-in fluid a predetermined amount.
  • the amount of gas generating chemical and encapsulated activators used in the drill-in fluid will depend on the amount of gas desired and, hence, the amount of foaming desired.
  • the gas generating chemical or chemicals utilized are combined with the well treating fluid in a general amount, depending on the amount of gas desired under downhole conditions, in the range of from about 0.1 percent to about 10 percent by weight of the drill-in fluid.
  • the activator or activators used and their amounts are selected for the activator's ability to cause the gas generating chemical or chemicals to generate gas at a particular temperature or range of temperatures, generally the temperature or range of temperatures at the drill tool.
  • the temperatures at which various activators cause a particular gas generating chemical to produce gas can be readily determined in the laboratory.
  • the amount of the activator included in the well treating fluid in the encapsulated form range from about 0.1 percent to about 10 percent by weight of the drill-in fluid.
  • a mixture of foaming and foam stabilizing surfactants can be combined with the drill-in fluid to facilitate the formation and stabilization of the drill-in fluid foam produced by the liberation of gas therein.
  • these foaming and foam stabilizing surfactants will be present in an amount from 0.01 percent to 10 percent by weight of the drill-in fluid, and can be present in an amount from 0.1 percent to 2 percent by weight of the drill-in fluid.
  • foaming and foam stabilizing surfactants is comprised of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant and an alkyl or alkene amidopropyldimethylamine oxide surfactant.
  • foaming agents include betaines; amine oxides; methyl ester sulfonates; alkylamidobetaines, such as cocoamidopropyl betaine; alpha olefin sulfonate; trimethyltallowammonium chloride; Cs-C 22 alkylethoxylate sulfates; and trimethylcocoammonium chloride.
  • foam stabilizers include fatty methyl ester surfactants, aliphatic alkyl sulfonate surfactants, aliphatic alkyl sulfate surfactants, a nanoparticle, and combinations thereof.
  • a water soluble viscosifier or gelled fluid can be used to adjust the viscosity of the drill-in fluid and/or to help increase foam stability.
  • the viscosifier can be selected from the group consisting of water soluble starches and modified versions thereof, water-soluble polysaccharides and modified versions thereof, water soluble celluloses and modified versions thereof, water soluble polyacrylamides and copolymers thereof, and combinations thereof.
  • suitable viscosifiers include biopolymers such as xanthan and succinoglycan, cellulose derivatives such as hydroxyethylcellulose and guar and its derivatives such as bydroxypropyl guar.
  • Water soluble viscosifiers can be present in an amount from about 0.01 percent to about 3 percent by weight of the drill-in fluid.
  • fluid loss control additives may be included in the drill-in fluid, including starch, starch ether derivatives, hydroxyethylcellulose, cross-linked hydroxyethylcellulose, and mixtures thereof.
  • the fluid loss control additive is starch.
  • the fluid loss control additive is present in the drill-in fluid in an amount sufficient to provide a desired degree of fluid loss control. More particularly, the fluid loss control additive is present in the drill-in fluid in an amount in the range of from about 0.01 percent to about 3 percent by weight.
  • Bridging agents may optionally be used. Bridging agents are generally solids added to a drilling fluid to bridge across the pore throat or fractures of an exposed rock thereby preventing loss of drilling fluid or excessive filtrate. Fluid loss control additives and bridging agents achieve a somewhat similar result; however, generally fluid loss control additives form a seal or filter cake to seal off the flow channel or path into the surrounding reservoir or rock without any substantial penetration and bridging materials have some degree of invasion or penetration into the pore space to mechanically bridge off or seal the reservoir or rock. Bridging materials are commonly used in drilling fluids and in lost circulation treatments. For reservoir applications, the bridging agent should be removable. Common products include calcium carbonate (acid-soluble), suspended salt (water-soluble) or oil-soluble resins. For lost circulation treatments, any suitably sized products can be used, including mica, nutshells and fibers. These products are also referred to as lost circulation material (LCM).
  • LCM lost circulation material
  • the bridging agent can comprise solid particulates or a degradable material and can be present in the drill-in fluid in an amount sufficient to create an efficient filter cake.
  • the bridging agent comprised of the degradable material is present in the well drill-in fluid in an amount ranging from about 0.1 percent to about 3 percent by weight.
  • solid particulates to be used as bridging agent include latex polymer, graphite, calcium carbonate, dolomite, celluloses, micas, sand or ceramic particles.
  • the degradable material comprises a degradable polymer or a dehydrated compound.
  • Examples of the degradable polymer include polysaccharides, chitins, chitosans, proteins, orthoesters, aliphatic polyesters, poly(glycolides), poly(lactides), poly(s-caprolactones), poly(hydroxybutyrates), polyanhydrides, aliphatic polycarbonates, poly(orthoesters), poly(amino acids), poly(ethylene oxides), or polyphosphazenes.
  • Examples of the dehydrated compound include anhydrous sodium tetraborate or anhydrous boric acid.
  • a method in accordance with one embodiment of the invention starts with providing a drill-in fluid comprising an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator.
  • the drill-in fluid can have other components such as fluid loss control agents, bridging agents and/or viscosifying agents; however, it is an advantage of the invention that the need for such additional agents is reduced or eliminated.
  • the drill-in fluid provided consists essentially of an aqueous fluid, a foaming agent, a foam stabilizer, a gas generating chemical and an encapsulated activator and the method in accordance with the invention does not rely on any substantial amounts of additional fluid loss control agents, bridging agents and/or viscosifying agents.
  • the drill-in fluid is introduced downhole into and through a drill string connected at its downhole end to a drill tool.
  • both the gas generating chemical and the encapsulated activator are admixed into the drill-in fluid prior to introduction into the drill string. While one or the other of the gas generating and encapsulated activator can be introduced into the drill-in fluid after the rest of the drill-in fluid has been introduced downhole, this would eliminate several advantages of the current invention and increase cost associated with the use of the drill-in fluid. For example, admixing the encapsulated activator downhole just prior to the drill tool would require a separate stream for the encapsulated activator and increase the cost and amount of equipment needed . The current invention does not need such separate streams for the components of the drill-in fluid; rather, all the components can be admixed at the surface and introduced into the drill string together.
  • the drill tool can be most common types of downhole drill tools, such as a drill bit or jet drill.
  • Drill bits or rotary drills are conventional drill tools that use teeth on the drill head to crush or grind up rock.
  • drill bits are hollow and have jets to allow for the expulsion of drilling fluid. The operation of the drill bit causes high shear regions within the hollow interior of the drill bit, at the jets and teeth of the drill bit and in the region outside the drill bit between the borehole wall and the drill bit where the drilling action is occurring to grind or drill rock or other substances.
  • the encapsulated activator upon exiting the drill bit, the encapsulated activator is de-capsulated or released by shearing action sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid at the drill bit teeth and between the drill bit and the borehole wall.
  • all or part of the de-capsulation to occur by a delayed encapsulation in which temperature or time of exposure to other compounds, such as the aqueous fluid, result in de-capsulation or release of the activator
  • such embodiments are subject to timing miscalculations and can result in the foaming of the drill-in fluid prior to reaching the drill bit or after the drill-in fluid has moved uphole from the region between the drill bit and the borehole.
  • Jet drills as used herein is used to refer to both conventional jet drills and hydrajets, unless otherwise indicated. Such jet drills release or jet a fluid through nozzles on the drill head, thus creating a high-velocity stream of fluid. Hydrajets use a fluid, typically an aqueous fluid, carrying small abrasive particles. The high-velocity or high pressure abrasive carrying fluid erodes or abrades away the rock. Conventional jet drills typically use drill-in fluid without added abrasives for the high-velocity stream.
  • the drill-in fluid described above can be used with or without abrasives in hydrajet or conventional jet drilling tools.
  • both hydrajet and conventional jet drilling tools there are high shear conditions at the nozzles and in the region outside the jet drill between the borehole wall and the jet drill where the drilling action is occurring to abrade or erode rock or other substances.
  • the encapsulated activator upon exiting the jet drill the encapsulated activator is de-capsulated or released by shearing action sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid between the jet drill and the borehole wall.
  • the thus created foamed drill-in fluid is circulated around the region between the drill tool and the borehole wall; thus cooling and lubricating the drill tool (typically with drill bits) and entraining drill cuttings into the foamed drill-in fluid.
  • the drill-in fluid is further circulated into an annulus formed between the wellbore and the drill string such that drill cuttings produced during drilling are carried by the foamed drill-in fluid back to the surface via the annulus.
  • the foamed drill-in fluid is recovered from the annulus, generally at the surface and the foamed drill-in fluid is then defoamed to form a defoamed drill-in fluid.
  • the drill-in fluid will be reused. Accordingly, the drill cuttings and other impurities can be removed from the drill-in fluid before, during or after defoaming. Subsequently, the defoamed and clean drill-in fluid will be admixed with additional amounts of the gas generating agent and additional amounts of the encapsulated activator to replace these components that were used downhole. The thus formed recirculation drill-in fluid is re-introduced into the drill string to thus repeat the use of the drill-in fluid as described above. Generally, the drill-in fluid will be recycled downhole many times with some fresh drill-in fluid added as necessary to make up for drill-in fluid lost during the operation. EXAMPLE
  • fresh water, potassium chloride (a clay stabilizer), cocoamidopropyl betaine (a foaming agent), an alkyl amidopropyldimethylamine oxide surfactant (a foam stabilizer), azodicarbonamide (a nitrogen gas generating chemical), and ammonium persulfate encapsulated with polyurethane (an encapsulated activator) are mixed together on the surface at a well site to produce a drill-in fluid at the well site.
  • the drill-in fluid comprises approximately 92 percent by weight of the aqueous fluid, approximately 1.0 percent by weight of the foaming agent, approximately 4.0 percent by weight of the gas generating chemical and approximately 3.0 percent by weight of encapsulated activator.
  • the drill-in fluid is then introduced downhole into and through a drill string penetrating the well bore and connected at its downhole end to a jet drill.
  • a jet drill As the drill-in fluid reaches the jet drill it flows through the hollow interior of the jet drill and through the jets on the end of the jet drill where it exits into the wellbore (or borehole) in the region between the borehole wall and the jet drill.
  • the encapsulated activator is de-capsulated by shearing action sufficiently to react with the gas generating chemical such that a gas is generated within the drill-in fluid and thus foams the drill-in fluid at the jet drill teeth and between the jet drill and the borehole wall.
  • the thus created foamed drill-in fluid is circulated around the region between the jet drill and the borehole wall; thus cooling and lubricating the jet drill and entraining drill cuttings into the foamed drill-in fluid.
  • the drill- in fluid is further circulated into an annulus formed between the wellbore and the drill string such that drill cuttings produced during drilling are carried by the foamed drill-in fluid back to the surface via the annulus.
  • the foamed drill-in fluid is recovered from the annulus at the surface and the foamed drill-in fluid is then defoamed to form a defoamed drill-in fluid.
  • the drill cuttings and other impurities are removed from the drill-in fluid after the fluid is defoamed.
  • the defoamed drill-in fluid is then recycled (by addition additional amounts of the gas generating agent and encapsulated activator) and recirculated into the drill string where it is again used as described above.
  • the drill-in fluid is successfully recycled downhole many times.

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  • General Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
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  • Organic Chemistry (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
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Abstract

La présente invention concerne des procédés de forage d'un puits de forage, dans lesquels un fluide de forage est moussé au niveau de l'outil de forage. Le procédé de l'invention consiste à fournir un fluide de forage comprenant un fluide aqueux, un agent moussant, un stabilisateur de mousse, un produit chimique générateur de gaz et un activateur encapsulé ; introduire le fluide de forage en fond de trou dans un train de tiges de forage relié à un outil de forage ; et faire sortir le fluide de forage de l'outil de forage, de sorte qu'au moment de sortir de l'outil de forage, l'activateur encapsulé est suffisamment dégagé de la capsule pour réagir avec le produit chimique générateur de gaz et produire un gaz dans le fluide de forage, ce qui permet de mousser le fluide de forage.
EP14754602.2A 2013-02-21 2014-02-12 Procédé pour améliorer l'efficacité d'un fluide de forage Withdrawn EP2959092A4 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US13/773,199 US20140231146A1 (en) 2013-02-21 2013-02-21 Method of enhancing drilling fluid performance
PCT/US2014/016060 WO2014130323A1 (fr) 2013-02-21 2014-02-12 Procédé pour améliorer l'efficacité d'un fluide de forage

Publications (2)

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EP2959092A1 true EP2959092A1 (fr) 2015-12-30
EP2959092A4 EP2959092A4 (fr) 2016-10-26

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US (1) US20140231146A1 (fr)
EP (1) EP2959092A4 (fr)
AR (1) AR094871A1 (fr)
AU (1) AU2014219296A1 (fr)
BR (1) BR112015016645A2 (fr)
CA (1) CA2898728C (fr)
MX (1) MX2015009249A (fr)
WO (1) WO2014130323A1 (fr)

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WO2017127105A1 (fr) * 2016-01-22 2017-07-27 Halliburton Energy Services, Inc. Additifs encapsulés destinés à une utilisation dans des opérations de formation souterraine
CA3008735A1 (fr) 2017-06-19 2018-12-19 Nuwave Industries Inc. Outil de coupe a jet d'eau
US10982124B2 (en) 2017-11-06 2021-04-20 Saudi Arabian Oil Company Drill-in fluid compositions and methods
CN114316923A (zh) * 2020-10-09 2022-04-12 中石化南京化工研究院有限公司 一种微泡沫钻井液用发泡剂体系
US11954800B2 (en) 2021-12-14 2024-04-09 Saudi Arabian Oil Company Converting borehole images into three dimensional structures for numerical modeling and simulation applications

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Publication number Publication date
CA2898728A1 (fr) 2014-08-28
EP2959092A4 (fr) 2016-10-26
AU2014219296A1 (en) 2015-07-09
US20140231146A1 (en) 2014-08-21
BR112015016645A2 (pt) 2017-07-11
AR094871A1 (es) 2015-09-02
CA2898728C (fr) 2017-10-17
WO2014130323A1 (fr) 2014-08-28
MX2015009249A (es) 2015-10-15

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