MX2008009660A - Wellbore fluid comprising a base fluid and a particulate bridging agent - Google Patents

Abstract

A wellbore fluid comprising a base fluid and a particulate bridging agent comprised of a sparingly water-soluble material selected from the group consisting of melamine (2,4,5- triamino-l,3,5-triazine), lithium carbonate, lithium phosphate (Li3PO4), and magnesium sulfite.

Description

POTATO FLUID FLUID COMPRISING A BASE FLUID AND A PARTICULATE AGENT FOR RESANADO FIELD OF THE INVENTION The present invention relates to drilling fluids used in the construction, repair or treatment of a perforation and to the removal of the filter cake deposited by the fluids for drilling on or in rock formations penetrated by the drilling.

BACKGROUND OF THE INVENTION Drilling fluids include drilling fluids, fluids for lost circulation, termination fluids (such as drilling pills and fluid for widening), and maintenance fluids (such as reoperation fluids, grinding fluids, fracturing fluids, solvents, aqueous fluids containing non-acidic dissolving agents, and fluids containing particulate deviating agents). Drilling fluids are used when drilling a hole through a porous and permeable rock formation, for example, a rock formation containing hydrocarbons. It is desirable that the fluid For drilling, minimize the damage to the permeability of the rock formation. For example, damage to the permeability of a rock formation containing hydrocarbons can result in production losses or a reduced ability of the formation to accept injected fluids (eg, water or fluids for treatment). Termination fluids are used during operations that occur in the so-called completion phase of a borehole (after boring the sentence and before starting the production of fluids from a rock formation to drilling or injection of fluids from the borehole towards a rock formation). Again, it is quite desirable that the termination fluids minimize the damage to the permeability of the rock formations. Fluids for maintenance can be used intermittently during the productive life of a perforation, for example, when performing reoperation, stimulation or correction operations in a rock formation penetrated by the perforation. For example, in cases where the maintenance fluid is a fluid for fracturing, it is quite desirable that the flow of fluid from the fractures that are induced in the walls of the body be minimized. perforation The drilling, finishing or holding fluids generally comprise a particulate solid resizing agent of a particle size which is large enough to resurface the pore grooves of a porous and permeable rock formation and an additive for filtration control ( often referred to as an "additive for fluid loss control"). The drilling, finishing or maintenance fluids deposit a layer of particles known as a "filter cake" on the walls of the perforations. In cases where the perforation penetrates a porous and permeable rock formation, the low permeability filter cake prevents large amounts of fluids ("filtrate") from being lost from the drilling fluid, termination or maintenance into the interior of the Rock formation and also prevents solids from entering the pores of the formation. The fluid that is lost from a fluid for drilling, termination or maintenance into a porous and permeable rock formation is called "filtering". The filter cake is constituted by the particulate dressing agent and the fluid loss control agent and may also include other solids which are present in the drilling fluid and which can be deposited on the walls of the fluid. drilling. After boring, completion or maintenance of the perforation, it is convenient to remove as much as possible of the filter cake before starting the production of fluids from a porous rock formation and permeable to the inside of the perforation or before Inject fluid into a permeable and porous rock formation from the perforation. Nevertheless, it is often difficult to access, and eliminate, substantial amounts of filter cake. If a large volume of drilling fluid is being lost through high conductivity ducts in the walls of a perforation into a porous and permeable rock formation, a lost circulation fluid is pumped into the borehole. which comprises a material for lost circulation (LCM for its acronym in English) suspended in a base fluid. High conductivity ducts are typically fissures, fractures or cavities in the walls of the perforation (where a cavity is a cavity, empty space or large pore in a rock formation). Fluids for lost circulation often comprise thicker particulate solids (LCM) than particulate fluxing agents for drilling, maintenance or termination fluids in order to resurface and seal high conductivity ducts within which the drilling fluid is being lost. Therefore, a relatively low permeability plug comprising the particulate LCM and optionally other solids is deposited from the circulation fluid lost in the high conductivity ducts. These particulate plugs can be difficult to remove from high conductivity ducts when you want to start the production of fluids from a rock formation into a production hole or the injection of fluids into a rock formation from a drilling hole. injection . Conventionally, the filter cakes are removed from the walls of the perforation by contacting the filter cakes with one or more fluids for cleaning. A common dressing agent for repairing the pore grooves of a porous formation and for clogging any high conductivity conduits (eg cracks) therein is calcium carbonate powder. The filter cake can be removed using a cleaning fluid comprising enzymes and oxidants to degrade the additive for fluid loss control before contacting the filter cake with a strongly acidic cleaning solution for a sufficient period of time to dissolve the agent for resoiling of particulate calcium carbonate. However, despite the current anti-corrosion steps, the strongly acidic solution often corrodes metal surfaces and finishing equipment such as sand control screens which causes early failure of such equipment. The solution for acidic cleaning may also be incompatible with the production formation and may cause damage to the formation. Furthermore, inefficient dissolution of the filter cake occurs when an acid cleaning solution reacts rapidly with a portion of the filter cake, opening the fluid communication between the cleaning fluid and the perforation and the permeable formation, after which cleaning fluid enters the formation without making contact with the remainder of the filter cake. Another problem arises when an expandable sand mesh is placed in an open hole in the perforation range adjacent to a hydrocarbon-containing formation. After the placement of the sand mesh, it is expanded to fit the diameter of the hole, providing excellent support for drilling and the exclusion of sand production. Unfortunately, this results in the filter cake being trapped between the expanded sand mesh and the formation so that it is very difficult to access the filter cake with a solution for cleaning. Low in such circumstances, it could be convenient if the filter cake were soluble in less corrosive and less harmful fluids, for example drilling fluids normally present. In this way you can finally reach the untreated or trapped filter cake and it is dissolved in the fluids. In cases where the filter cake is deposited on and / or on the walls of a borehole for hydrocarbon production, the hydrocarbon-containing formation usually produces a significant proportion of water. In cases where the filter cake is deposited on and / or on the walls of a well for water injection or a water producing well, again the filter cake is exposed to large volumes of water over a prolonged period of time. In cases where the filter cake is deposited on and / or on the walls of a geothermal perforation, the filter cake is exposed to hot water and steam. Accordingly, particulate solids have been used or proposed as agents formed from a water-soluble salt (for example, alkali metal halides) or a poorly water-soluble salt (for example magnesium borate and magnesium salts of acids). carboxylic) in the fluids for drilling or maintenance. Therefore, the filter cakes that contain the agent for soluble filtering in Water or slightly soluble in water have been eliminated by contacting the filter cake with an aqueous saline solution which is sub-saturated with respect to the water soluble or sparingly water soluble salt. These water soluble or poorly water-soluble dressing agents can be used in fluids for either aqueous or oil-based treatment with the proviso that the water-based fluid is saturated with respect to the water soluble or sparingly soluble salt in water However, there remains a need for additional drilling fluids in which the dressing agent is made up of a poorly water soluble material.

SUMMARY OF THE INVENTION Accordingly, the present invention relates to a drilling fluid comprising a base fluid and a particulate resizing agent comprised of a poorly water-soluble material that is selected from the group consisting of melamine (2, 5-triamine). -l, 3, 5-triazine), lithium carbonate, lithium phosphate (Li3P04), and magnesium sulphite, preferably melamine and lithium carbonate.

DETAILED DESCRIPTION OF THE INVENTION The term "drilling fluid" as used in the present invention encompasses drilling fluids, fluids for lost circulation, termination fluids such as drilling pills and fluid for broadening, and maintenance fluids such as fluids for neutralization, fluids for reoperation, grinding fluids, fracturing fluids, solvents, non-acidic aqueous solution agents, and fluids containing particulate deviating agents. The drilling fluid of the present invention is suitable for use in a variety of boreholes including oil and / or gas producing boreholes, water or gas injection wells, water producing wells and geothermal wells. The poorly water-soluble materials that have been selected for use as the particulate resizing agent have a solubility in water at a temperature of 25 ° C of less than 7% by weight, preferably less than 2% by weight. In addition, these materials have a solubility in water at a temperature of 80 ° C of less than 7% by weight, preferably less than 3.5% by weight. Optionally, an additive is included to control fluid loss in the drilling fluid of the present invention. The present invention also provides a method for forming a removable filter cake on the walls of a perforation that penetrates a porous and permeable rock formation comprising the steps of: (a) placing a drilling fluid in the bore in which the The fluid for drilling comprises a base fluid and a particulate for resizing consisting of a poorly water soluble material which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate (LÍ3PO4), and magnesium sulphite, preference, melamine and lithium carbonate; Y (b) allowing the particulate for reaming to be deposited from the drilling fluid on and / or in the walls of the perforation to thereby form the removable filter cake, thereby reducing the loss of fluid into the formation through the filter cake. Suitably, the particulate resizing agent can cure the pore throats of the rock formations penetrated by the perforation and / or can enter any cracks, fissures, fractures, or holes in the perforation wall. Optionally, an additive is included to control fluid loss in the drilling fluid.

By "stirring" it is meant that the filter cake can be removed without pumping a specialized cleaning fluid into the borehole. In other words, the filter cake can be self-removable. The filter cake is allowed to accumulate in the walls of the perforation because the drilling fluid pressure in the perforation is maintained above the pore pressure of the porous and permeable formation which is penetrated by the perforation. Preferably, the differential pressure between the drilling fluid pressure in the drilling and the pore pressure is at least 14.06 kg / cm2. In cases where the drilling is a drilling for the production of hydrocarbons, the reagent can be eliminated by putting the well into production because water is produced in conjunction with the hydrocarbon which dissolves the poorly soluble material in water. In cases where the drilling is a well for water production or a geothermal well, the reagent can be eliminated by putting the well into production because the poorly soluble material in water dissolves in the water that is produced. In cases where the perforation is a well for water injection, the filter cake can be eliminated by initiating the injection of water because the injected water dissolves the material a little soluble in water. Therefore, both the water produced and the injected water are sub-saturated with respect to the poorly soluble material in water. The dressing agent can be completely solubilized over time in water or alternatively it is solubilized to the extent that the particles are sufficiently small in size to allow their removal from formation with the water produced or injected. The time required to solubilize the particles depends on a number of factors including, the temperature in the perforation, the size and shape of the particles of the dressing agent, and the amount of water to which the filter cake is exposed. It is expected that the filter cake will survive for less than 200 hours when a production well is put into production or when water is injected into an injection well. Optionally, if rapid dissolution is required, a cleaning fluid can be pumped into the borehole. The cleaning fluid may be an aqueous fluid that is sub-saturated with respect to the dressing agent. Preferably, the cleaning fluid is an aqueous solution of an acid, preferably an aqueous solution of a weak acid or a precursor of a weak acid. Preferably, the weak acid is selected from the group consisting of acid formic acid, citric acid, acetic acid, lactic acid, glycolic acid, succinic acid, and acid sequestrants such as those based on partially neutralized ethylenediaminetetraacetic acid (EDTA). Preferably, the weak acid precursor is selected from materials that can be hydrolyzed to produce weak acids such as homopolyethers of polyglycolic or polylactic acid and orthoesters such as orthoformate esters. Preferably, the weak acid or acid precursor is present in the cleaning fluid in an amount between 1% and 20% by weight. An advantage of using an aqueous solution of a weak acid or an aqueous solution of a weak acid precursor is that the cleaning fluid is less corrosive to metal surfaces and equipment than the strong acids used to dissolve inorganic bonding agents. conventional ones such as calcium carbonate. An additional advantage of the poorly water-soluble materials used in the present invention is that even partial reaction with an acid forms products having a greater water solubility. Therefore, lithium carbonate is converted to lithium bicarbonate, lithium phosphate (LÍ3PO4) is converted to lithium hydrogen phosphates, and magnesium sulphite is converted to magnesium bisulfite after partially reacting with an acid.

All these products are of a much higher solubility than their precursors which are poorly soluble in water. In addition, the amine groups that are present in the melamine are protonated under slightly acidic conditions, greatly increasing the water solubility of the reagent. In cases where the particulate relining agent sparingly soluble in water is constituted by magnesium sulphite, the cleaning fluid may comprise an aqueous solution of an oxidizing agent which can convert the magnesium sulphite into water-soluble magnesium sulfate. Therefore, magnesium sulfate has a much higher solubility in water than magnesium sulphite. Suitable oxidizing agents include hydrogen peroxide, persulfate salts, and peracids such as peracetic acid. Preferably, the oxidizing agent is present in the cleaning fluid in an amount of 1 to 20% by weight. Optionally, the cleaning fluid also comprises a weak acid or a precursor of a weak acid. In cases where the particulate relining agent poorly soluble in water is constituted by melamine, it is contemplated that the removable filter cake can be removed from the walls of a perforation by placing an aqueous washing fluid down hole and allowing the fluid to flow through. aqueous wash soak the interval of the perforation where you want to eliminate the filter cake. The soaking time must be sufficient for the aqueous washing fluid to be heated to a temperature of at least 60 ° C, preferably at least 75 ° C, for example, at least 90 ° C. Because the solubility of the melamine increases relatively rapidly with increasing temperature, the particulate dressing agent can be completely dissolved in the aqueous wash fluid or it is solubilized to the extent that the particles are one size sufficiently small to allow its removal from formation. The aqueous wash fluid is heated to the desired temperature due to the transfer of geothermal heat from the formation. Typically, it could take at least several hours, for example, about 1 day for the aqueous wash fluid to be heated to the desired temperature. In general, the operator will be able to determine that a sufficient period of time has elapsed when the speed of fluid loss from drilling to formation increases. The rate of dissolution in water of the reagents is also increased by the presence of carbon dioxide. Therefore, it can be expected that the high partial pressures of carbon dioxide that are often present in fluids produced from hydrocarbon-containing formations accelerate the dissolution of the dressing agent. Optionally a downhole cleaning fluid is placed and allowed to soak through the perforation range where it is desired to remove the filter cake for a sufficient period of time either to completely dissolve the dressing agent or to solubilize the agent for resizing to the extent that the particles are of a sufficiently small size to allow their removal from formation. The cleaning fluid may contain enzymes or oxidizing agents to degrade the polymers for fluid loss control and viscosifiers that accumulate in the filter cake, and may contain acids or acid precursors to accelerate the dissolution of the solids for reaming. Preferably, the optional cleaning solution is allowed to soak for approximately 2 to 24 hours. In general, the operator will be able to determine that a sufficient period of time has elapsed when the speed of fluid loss from drilling to formation increases. After this, a wash fluid (eg, an aqueous fluid such as water or seawater or a diluted brine) can be pumped at a high speed into the interior of the borehole with in order to create turbulent cleaning conditions whereby the filter cake remaining from the walls of the perforation is removed. Alternatively, the remaining filter cake can be removed by producing water from the formation or by injecting water into the formation. Preferably, the drilling fluid is selected from (a) a drilling fluid; (b) a fluid used to control the circulation loss (referred to as "fluid for circulation loss"); (c) a termination fluid used during termination operations; and (d) a well maintenance fluid used when performing reoperation, stimulation or correction operations. Therefore, in a preferred embodiment of the present invention there is provided a method for drilling a borehole through porous and permeable rock formation using a drilling fluid comprising a base fluid, an additive for fluid loss control, and a particulate agent for resizing constituted by a poorly soluble material in water · which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate (LÍ3PO4), and magnesium sulphite in which the fluid pressure for drilling is maintained above the pressure in the porous rock formation and permeable so that a filter cake is deposited on and / or in the walls of the perforation and reduces the loss of fluid from the drilling fluid to the rock formation. With the phrase that is deposited "on the walls of the perforation" it is meant that the filter cake can be deposited in any cracks, fractures, fissures or cavities that are present in the walls of the perforation. Appropriately, drilling that is drilled using this preferred embodiment of the present invention is a borehole for hydrocarbon production (an oil or gas well), a borehole for injection (eg, a well for water or gas injection) , a water producing perforation or a geothermal drilling. In another preferred embodiment of the present invention, a method is provided for controlling the loss of fluid from a borehole to a porous and permeable rock formation through a high conductivity duct extending from the bore into the rock formation which comprises the steps of: (a) placing a fluid for circulation loss in the perforation in which the fluid for circulation loss comprises a suspension of particulate material for leakage circulation (LCM) in a base fluid in which the LCM is suspended in the base fluid in an amount of at least 14,175 kg / m3, preferably at least 28.35 kg / m3, more preferred at least 56.7 kg / m3, and still more preferred at least 85.05 kg / m3, and is constituted by a poorly water-soluble material that is selected from the group consisting of melamine, lithium carbonate, phosphate lithium (LÍ3PO4), and magnesium sulphite; and (b) allowing the LCM to accumulate at, or at the entrance of, the high conductivity duct, thereby forming a removable low permeability plug that overhangs the duct, thereby reducing the loss of fluid to the formation through of the conduit. By "removable" it is meant that the cap can be removed without the aid of a specifically designed cleaning fluid. The suspension is pumped into the perforation range where a high conductivity duct (such as a crack) is present in the perforation wall and through which the fluid is lost to the porous and permeable rock formation, by example, a rock formation containing hydrocarbon. The filtration of the suspension results in the deposition of the particulate LCM in the high conductivity duct so such that the conduit is filled with a solid package of LCM particles. Optionally, an agent for fluid loss control in the suspension may be present thereby helping to seal the high conductivity duct. Preferably the duct seal is made more complete when a subsequent drilling fluid such as a drilling fluid, in particular a drilling fluid with low fluid loss, forms a waterproof filter cake after the particulate LCM plug. Even in another preferred embodiment of the present invention there is provided a method for controlling fluid loss from a termination fluid to a permeable and porous rock formation penetrated by a bore: (a) by placing a termination fluid in the borehole in the which the termination fluid comprises a base fluid, an additive for fluid loss control, and a particulate for resizing consisting of a poorly water soluble material that is selected from the group consisting of melamine, lithium carbonate, phosphate of lithium, and magnesium sulphite; and (b) maintaining the fluid pressure for termination in the bore above the pore pressure of the rock formation so that it is deposited a filter cake on or in the walls of the perforation. Suitably, the termination fluid (and also the drilling fluid referred to above) additionally contains a viscosity agent or agents such as xanthan gum, hydroxyethylcellulose, welan gum (e.g., Biozan ™; from Kelco) or "diutan" gum (eg, Geovis XT ™; from Kelco). The finishing fluid that is placed in the hole can fill the entire hole. Alternatively, the termination fluid can be used as a pill of sufficient volume to fill the perforation range to be "finished" by filling the remnant of the perforation with a second fluid having an appropriate density for control purposes. of well. Therefore, the density of the second fluid is chosen such that fluid does not flow from a rock formation into the borehole. It is contemplated that the second fluid may be a brine that is substantially free of suspended solids. It is also contemplated that the perforation may be a piped perforation that is drilled in a range of the perforation lying through a porous and permeable rock formation, eg, a rock formation containing hydrocarbons. Therefore, the cake of The filter is deposited from the termination fluid in the perforation tunnels formed in the piped perforation, thereby reducing the fluid loss from the termination fluid to the formation. Even in a further embodiment of the present invention, a method is provided for controlling the loss of fluid from a reoperation fluid to a range of a borehole that lies through a porous and porous rock formation in which the method comprises the steps of: (a) pumping a sufficient volume of a first reoperation fluid to fill the range of the perforation lying through the porous and permeable rock formation in which the first reoperation fluid 'comprises a base fluid, a additive for control of fluid loss, and a particulate for resizing consisting of a poorly water soluble material that is selected from the group consisting of melamine, lithium carbonate, lithium phosphate, and magnesium sulphite in such a way that a removable filter cake is deposited from the first fluid for reoperation in said interval of the perforation on the walls of the perforation and within any cracks, fractures or cracks in it; (b) pump a second reoperation fluid within the perforation in which the second reoperation fluid is of a density sufficient to at least counteract the pressure of the porous and permeable rock formation; and wherein the filter cake deposited in step (a) reduces the loss of fluid from the reoperation fluids to the formation of porous and permeable rock. The second reoperation fluid may be of the same composition as the first reoperation fluid or may be of a different composition, for example a brine or solid-free oil. In the case of aqueous reoperation fluids, it is preferred that the second reoperation fluid be substantially saturated with respect to the sparingly water-soluble material that constitutes the particulate agent for reattaining the first reoperation fluid. The first reoperation fluid is used to seal the formation to prevent fluid loss from the second reoperation fluid while the second reoperation fluid is used to perform functions such as well control maintenance (hydrostatic head), circulating debris such as the downhole equipment "ground" out of the hole (eg balers or "ground" screens), to provide a low viscosity fluid to allow easy movement of the tools in and out of the borehole and so that act as a "re-termination" fluid. In cases where the perforation is a piped perforation that is drilled in the perforation interval through porous and permeable rock formation, the filter cake is deposited from the first reoperation fluid in the perforation tunnels in the perforation of the perforation, thereby reducing the loss of fluid from the second reoperation fluid to the formation. Wells that require "reoperation" are often depleted hydrocarbon production wells in which the rock formation containing hydrocarbons has a low pore pressure. Accordingly, the hydrostatic head of the second reoperation fluid in the perforation range through the hydrocarbon-containing rock formation may be over-exceeded with respect to the pore pressure in the depleted hydrocarbon-containing rock formation even when the second reoperation fluid is a simple low density fluid such as water (e.g., sea water), or an oil. Accordingly, the ability to control fluid loss using the method described above is more important at high differential pressures (in which the pressure of the second reoperation fluid in the borehole is significantly more high that the pore pressure of the rock formation). Fracturing fluids generally comprise a support agent (eg, sand particles or ceramic globules) suspended in an aqueous base fluid which is normally made viscous using a polymer or a viscoelastic surface active agent such that the The support that is used to keep the fractures open is transported efficiently to the interior of the fractures that are created when the fracturing fluid is pumped at high pressure into a porous and permeable rock formation. However, if the fracturing fluid drains very rapidly into the formation, the high pressure dissipates and the fracture stops growing. Runoff control is usually accomplished by dispersing ground particles such as silica flour in the fracturing fluid to block / repair the exposed pores in the fracture that are accepting "runoff". Unfortunately, materials such as silica can cause at least some permanent obstruction of the pores of the formation. Accordingly, even in another preferred embodiment of the present invention there is provided a method for fracturing a porous and permeable rock formation comprising: injecting a fracturing fluid within a range of a bore through the rock formation to be fractured in which the fracturing fluid comprises a base fluid, support agent, an agent for viscosity, and a particulate for runoff control consisting of a sparingly soluble material in water that is selected from the group consisting of melamine, lithium carbonate, lithium phosphate, and magnesium sulphite; and maintaining the pressure of the fracturing fluid in the perforation range through the formation of rock above the fracture pressure of the formation whereby the support agent enters and keeps open the fractures that form in the wall The perforation and particulate agent for runoff control seals the exposed pore grooves in the walls of the fracture. An advantage of this preferred embodiment of the present invention is that the pressure of the fracturing fluid in the growing fracture is maintained as much as possible above the fracturing pressure of the rock formation by reducing the runoff of fluid into the formation and therefore reducing the pressure dissipation towards the formation. In cases where fractures are formed in a formation of rock containing hydrocarbons penetrated by a production well, the particulate material for remelting dissolves in the water that is produced jointly after returning the perforation to production, thereby improving the flow of fluid from the formation containing hydrocarbons. In cases where the fractures are formed in a porous and permeable rock formation penetrated by a well for water injection, the particulate material for resoiling dissolves in the water that is injected into the rock formation, thereby improving the flow of fluid from the injection well to the interior of the formation. In another embodiment of the present invention, a method is provided for diverting non-acidic treatment fluids away from high permeability rock formations or high conductivity ducts and toward low permeability and / or partially clogged rock formations or ducts. of lower conductivity using a treatment fluid comprising a non-acidic fluid and a particulate for resizing consisting of a sparingly soluble material in water which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate (Li3P04 ), and magnesium sulphite. For example, in cases where the non-acidic fluid is an aromatic solvent, the treatment fluid can be used to dissolve wax deposits and / or Asphaltene that obstruct the flow channels in oil wells (and therefore reduce oil production). The method comprises pumping a slurry comprising the particulate for resizing suspended in an aromatic solvent into a hydrocarbon production bore in such a way that a filter cake is formed in or on a high permeability rock formation or the agent particulate for sealing between and sealing the high conductivity ducts (or flow channels) in the walls of the perforation thereby limiting the loss of aromatic solvent from the perforation. Accordingly, the aromatic solvent is diverted into low conductivity conduits (or flow channels) that may be damaged by deposits of asphaltene and / or wax, thereby improving the dissolution of the deposits by the aromatic solvent. The preferred characteristics of the drilling fluid of the present invention are described below. The base fluid of the drilling fluid may be water, an oil (e.g., a mineral oil), a solvent (e.g., an aromatic solvent), or a mixture thereof (e.g., an oil-in-water emulsion). Generally speaking, the base fluid is present in the drilling fluid in an amount in the range of about 30 to 99% by weight of the fluid, preferably, about 70 to 97% by weight. In cases where the base fluid is water, it is preferred that the base fluid be an aqueous solution of a water soluble salt that increases the density. The water-soluble salt which increases density can be selected from the group consisting of alkali metal halides (eg, sodium chloride, sodium bromide, potassium chloride and potassium bromide), alkali metal carboxylates (eg example, sodium formate, potassium formate, cesium formate, sodium acetate, potassium acetate or cesium acetate), sodium carbonate, potassium carbonate, alkaline earth metal halides (eg, calcium chloride and calcium bromide ), and zinc halide salts. Alternatively, density control can be provided to the water-based drilling fluid using insoluble weighting agents. Suitable weighting agents include suspended mineral particles such as ground barites, iron oxides, (eg, hematite), ilmenite, calcite, magnesite (MgCO3), dolomite, olivine, siderite, hausmannite or suspended metal particles. In cases where the fluid is an oil, it is preferred that the oil be selected from the group that It consists of mineral oils, synthetic oils, asters, kerosene and diesel. The base fluid may also be an oil-in-water emulsion comprising minute droplets of an aqueous phase dispersed in a continuous oil phase. Suitably, the aqueous phase of the emulsion comprises an aqueous solution of a water soluble salt which increases the density whereby the density of the drilling fluid is increased. Appropriate density-increasing water-soluble salts were indicated above. Preferably, the salt concentration in the tiny dispersed droplets of the aqueous phase is adjusted to provide a water activity similar to that of the underground formation which comes into contact with the drilling fluid. The continuous oil phase can be any oil in which an aqueous solution of salts can be emulsified. The appropriate oils are indicated above. An advantage of an oil-in-water emulsion is that it increases both the filtration control (because the tiny drops of the emulsion block the flow of fluid through the filter cake) and the viscous properties of the fluid. The term "fluid for water-based perforation" as used in the present invention encompasses drilling fluids in which the base fluid is an emulsion oil in water. Density control can also be provided to the oil-based drilling fluid using weighting agents. Suitable weighting agents are as indicated above for water-based drilling fluids. In cases where the base fluid is water, the particulate for resizing consists of a sparingly soluble material in water which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate, and magnesium sulphite (from hereinafter "particulate agent for poorly water-soluble resizing") is dosed into the drilling fluid at a concentration that is significantly higher than its solubility in water at the temperature found downstream thereby ensuring that at least one portion of the solids for ream remain suspended in the drilling fluid. Alternatively, the poorly soluble water-soluble particulate can be protected with a hydrophobic coating that can be dissolved in a liquid hydrocarbon produced, for example, a produced oil or a gas condensate produced. However, such coated particulate dressing agents should not be used when drilling or terminating water injection wells or wells. of gas that are free of gas condensate. Generally speaking, the particulate repellent agent poorly soluble in water is present in the drilling fluid in an amount sufficient to create an efficient filter cake that provides the desired level of fluid loss control. Typically, the particulate unwrapping agent poorly soluble in water is present in the drilling fluid in an amount in the range of 1 to 70% by weight, preferably 2 to 50% by weight, more preferred, 3 to 30% by weight , in particular 3 to 15% by weight. High doses are preferred for fluids for loss circulation, for example 10 to 60% by weight. The desired particle size distribution of the sparingly soluble particulate material in water is determined by the size of any fractures and the like within which the drilling fluid is being lost or by the size of the pore throat of the formation that is going to drill or treat. Typically, for use as a lossy circulation material, the particulate unwrapping agent poorly soluble in water has a particle size distribution in the range of about 50 microns to about 10 mm, preferably 50 microns to about 2 mm. For use as a solid for a fluid in drilling fluid, maintenance or termination, the particulate agent for low water-soluble dressing has a particle size distribution in the range of about 0.1 microns to 600 microns, preferably 0.1 to 200 microns, and more preferably 0.1 to 100 microns. Preferably, the particulate resinous material that is poorly soluble in water has a broad polydispersed size distribution. The materials (lithium carbonate, lithium phosphate, magnesium sulphide and melamine) can be obtained as crystalline materials of the desired size or as crystals or granules that can be milled to the desired size. The particulate resinous material that is poorly soluble in water may be in the form of substantially spherical particles or may be irregular in shape. More than one particulate reagent may be used, which is poorly soluble in water in the drilling fluid. The drilling fluids may additionally comprise one or more of the following materials: an agent for particulate resizing or for conventional weighting, for example barite; acid soluble materials such as calcium carbonate; water soluble materials such as alkali metal halides; and, other materials poorly soluble in water such as magnesium borate and magnesium salts of carboxylic acids. Sayings conventional particulate reaming agents can be employed in either an oil-based drilling fluid or in a water-based drilling fluid. In cases where the conventional particulate dressing agent is comprised of a water-soluble or sparingly soluble material in water, it is used in a water-based fluid in amounts greater than the saturation concentration of the water soluble or sparingly soluble material in water in water at the conditions found downstream to provide particles suspended from the agent for conventional particulate retanning. Water-borne drilling fluids may additionally comprise particulate solid dressing agents constituted by oil-soluble materials such as resins. Suitable resins include thermoplastic resins obtained from the polymerization of hydrocarbons, having an amorphous or crystalline structure which allows them to be ground and milled at room temperature and at the same time retain their strength so that they remain non-deformable when they undergo pressure in the pores and fissures of a rock formation. These resins have a melting point above the temperature found downstream and are insoluble in fluids for water-based treatment but are soluble in crude oils and gas condensates produced. Examples of preferred resins include coumaron-indene resins, and alkylated aromatic resins. Preferably, the water-soluble particulate relining agent used in the present invention comprises a significant portion of the suspended solids contained in the drilling fluid and therefore in the filter cake. Suitably, the particulate agent for poorly water-soluble dressing constitutes at least 15% by volume, preferably at least 30% by volume, more preferred at least 60% by volume of suspended solids from the drilling fluid ( the rest being particulate agents for conventional grinding, weighting agents, drilled solids, and clays). Without wishing to be bound by any theory, it is believed that the dissolution of the particulate agent for poorly water-soluble dressing creates holes in the filter cake whereby said cake becomes permeable. In cases where the filter cake is formed in a production well, the filter cake is easily degraded when the well is put into production because the produced fluids flow more freely through the permeable filter cake. Accordingly, other solids that are deposited on the filter cake are entrained in the fluid produced in such a way that the filter cake is Removes from the perforation wall. In cases where the drilling fluid is a water-based fluid, the drilling fluid may comprise additional additives to improve the performance of the drilling fluid with respect to one or more properties. Examples of additives that can be added to waterborne drilling fluids include viscosifiers, weighting agents, water-soluble density-increasing salts, agents for fluid loss control (also known as additives for filtration control), agents for pH control, hydration inhibitors of clay or shale (such as polyalkylene glycols), bactericides, surfactants, solid and liquid lubricants, gas hydrate inhibitors, corrosion inhibitors, defoamers, scale inhibitors, emulsified hydrophobic liquids such as oils, acid gas scrubbers (such as hydrogen sulphide scrubbers), thinners (such as lignosulphonates), demulsifiers and surfactants designed to aid in the cleaning of invaded fluid from production formations. Water-soluble polymers can be added to a water-borne drilling fluid to impart viscous, dispersion and solids properties to the fluid. filtration control. A wide range of water-soluble polymers can be used for an aqueous-based drilling fluid including cellulose derivatives such as carboxymethylcellulose, hydroxyethylcellulose, carboxymethyl-hydroxyethylcellulose, sulfoethylcellulose; starch derivatives (which may be intertwined) including carboxymethyl starch, hydroxyethyl starch, hydroxypropyl starch; gums of bacterial origin including xanthan, welan, diutan, succinoglucan, scleroglucan, dextran, pullulan; gums obtained from plants such as guar gum and locust bean gums and their derivatives; synthetic polymers and copolymers obtained from any suitable monomers including acrylic acid or methacrylic acid and their hydroxyl esters (for example hydroxyethylmethacrylic acid), anhydride or maleic acid, sulphonated monomers such as styrenesulfonic acid and AMPS, acrylamide and substituted acrylamides, N-vinylformamide and N-vinylacetamide, N-vinylpyrrolidone, vinyl acetate, N-vinylpyridine and other cationic vinyl monomers (e.g., diallyl dimethyl ammonium chloride, DADMAC); and any other water-soluble or water-expandable polymers known to those skilled in the art. In general terms, the viscosifying water soluble polymers are present in the drilling fluid of the present invention in a sufficient quantity to maintain the solids of resanado and of weighting in suspension and to provide an efficient cleaning of the pit of remains such as the cuts of drilling. The viscosifying polymer may be present in the drilling fluid in an amount in the range of 0.567 to 14.175 kg of viscosifier per cubic meter of drilling fluid, preferably 1.4175 to 8.505 kg per cubic meter of drilling fluid. Rheological control (eg, gelling properties) can also be provided to the water-based drilling fluid by adding clays and / or other inorganic fine particles. Examples include bentonite, montmorillonite, hectorite, atapulguite, sepiolite, Laponite ™ (from Laporte) and mixed metal hydroxides. An additive for fluid loss control can be used to fill the void spaces between the particulate for reaming. In addition to the water-soluble polymers indicated above, examples of additives for fluid loss control for water-based drilling fluids include lignite treated with caustics, modified lignites, entangled lignosulfonates and the like. Therefore, these additives for fluid loss control are dissolved macromolecules which can be adsorbed onto the solids for dressing or are macromolecules that are in colloidal dispersion in the water-based fluid, for example, a hydrated polymer that adopts a helical conformation when dispersed in the aqueous-based fluid making the hydrated polymer occlude micrometer or nanometer-sized pores in the filter cake. Appropriate pH control agents for aqueous-based drilling fluids include calcium hydroxide, magnesium hydroxide, magnesium oxide, potassium hydroxide, sodium hydroxide, and the like. In cases where the drilling fluid is an oil-based fluid, the drilling fluid may comprise additional additives to improve the performance of the drilling fluid with respect to one or more properties. Examples of additives that can be added to oil-based drilling fluids include viscosifiers, surfactants (to form stable oil-in-water emulsions and to impregnate the surface of mineral weighting agents with oil), additives for fluid loss control ( also known as additives for filtration control), lubricants (solids and liquids), and acid gas scrubbers (for example, hydrogen sulfide scrubbers). A viscosifier can be added to the fluid to oil-based perforation to impart viscosity properties, solids suspension and hole cleaning properties to the fluid. Normally the viscosifier is a montmorillonite or hectorite clay that has been treated with quaternary fatty acid ammonium salts to cause the clay to disperse and exfoliate in the oil-base drilling fluid. Polymers and oil-soluble oligomers can be used as rheology modifiers. Surfactants that can be added to the oil-based fluid to form stable water-in-oil emulsions and to impregnate with oil the surface of the mineral weighting agents include fatty acids such as wood oil fatty acid (TOFA). ) and TOFA condensation products with polyalkyleneamines such as triethylene tetramine. The resulting fatty acid amidoamine and the imidazoline products can be used as such or these can be further reacted with, for example, maleic anhydride to improve their performance. In cases where the surfactant contains a carboxylic acid functional group, said groups are usually converted to the corresponding calcium salts by the addition of lime. Additives for fluid loss control Suitable additives that can be added to the oil-base drilling fluid include asphalt, blown asphalt, sulfonated asphalt, gilsonite, fatty acid amine-modified lignite, and synthetic polymers soluble / expandable in oil. The present invention is illustrated below with respect to the following examples.

Solubility tests The following tests show the solubility in water and in aqueous acid solutions of materials that are poorly soluble in water.

EXAMPLE 1 Solubility of melamine In the following table 1 the solubility of melamine in water is provided through a range of temperatures. The person skilled in the art will understand that all that is required is a sufficient amount of water to dissolve the particulate melamine deposited in a well, especially if the well is allowed to warm to its natural temperature (predominant) after the cooling experienced during drilling of a hole or during the injection of cold water from the surface. By Consequently, particulate melamine can be automatically cleaned (dissolved) in water that could be produced from a well along with hydrocarbons, or in water that is pumped into an injection well to maintain reservoir pressure.

TABLE 1 Melamine is also readily soluble in warm or hot acids such as acetic acid and hydrochloric acid. Therefore, a mixture of melamine (25.2 g, 0.2 M), 250 ml of water and 24 g of acetic acid (0.4 M) produces a clear solution when heated to a temperature of 80 ° C. Similarly, a mixture of melamine (126 g, 1) and 1985 ml of 1.0075 M hydrochloric acid produces a clear solution when heated to a temperature of 83 ° C.

The solubility of melamine in acidic aqueous solutions is desirable in cases where the stimulation of the well is contemplated by injection of acid, or in cases where large amounts of particulate melamine are placed in the well, for example as plugs of circulation lost in fractured formations.

EXAMPLE 2 Solubility of lithium carbonate In the following table 2 the solubility of lithium carbonate in water is provided through a temperature range. As for example 1, the person skilled in the art will understand that all that is required is a sufficient amount of water to dissolve the lithium carbonate particles that are deposited in a well. As indicated above, this may be water produced or water being pumped into an injection well or an aqueous fluid placed in the well for the purpose of dissolving the lithium carbonate particles. The reduction in solubility with increasing temperature is an advantage in cases where particulate lithium carbonate is used in higher temperature wells (eg wells having a bottomhole temperature (BHT) of 100). ° C or greater) in the sense that the premature dissolution of the solid particles is more easily avoided.

TABLE 2 Lithium carbonate also dissolves rapidly in acids. For example, acetic acid reacts with lithium carbonate to generate lithium acetate which is very soluble in aqueous solutions while hydrochloric acid reacts with lithium carbonate to generate the highly soluble lithium chloride salt. The ability to remove particulate lithium carbonate by pumping an acid into a well is an advantage in cases where large amounts of particulate lithium carbonate are placed in the well, for example as plugs of circulating material lost in fractured formations . Lithium carbonate also shows an increased solubility in water in the presence of dioxide carbon, which is often found in fluids produced from oil wells or gas wells (due to the formation of lithium bicarbonate, L1HCO3). For example, at a temperature of 60 ° C and at a pressure of 50 atmospheres of C02, 100 grams of saturated solution contain 9.61 grams of L1HCO3. The high solubility of L1HCO3 is particularly convenient in gas wells because the gas in formation is inevitably almost saturated with water vapor and usually contains high concentrations of CO2. As the gas flows through the gas-carrying formation into a gas production well, the pressure is reduced causing adiabatic cooling and water condensation. The condensed water together with the high concentration of C02 therefore dissolves the particulate lithium carbonate residues without the need to pump fluids for dissolution from the surface.

EXAMPLE 3 Solubility of magnesium sulphite In the following table 3 the solubility of magnesium sulfate in water is provided through a range of temperatures. As for examples 1 and 2, all that is needed is a sufficient amount of water to Dissolve the particulate magnesium sulphite deposited in a well. Therefore, the particulate magnesium sulphite residues are automatically cleaned (dissolved) in the water that could be produced together with the hydrocarbons, or in the water that is pumped into an injection well to maintain the reservoir pressure. Alternatively, water or aqueous mixtures can be pumped into the well to dissolve particulate magnesium sulphite residues.

TABLE 3 Magnesium sulphite also readily dissolves in aqueous solutions of acids such as acetic acid or hydrochloric acid to produce sulfur dioxide and magnesium acetate or magnesium chloride very soluble respectively. Even the partial acidification up to magnesium bisulfite is effective to dissolve the particulate magnesium sulphite since the magnesium bisulfite is very soluble in water. For example, magnesium bisulfite can be commercially available as a 30% by weight aqueous solution of Sigma Aldrich. Alternatively, oxidizing agents such as hydrogen peroxide can cause dissolution of magnesium sulphite by converting it into soluble magnesium sulfate (62.9 g of magnesium sulfate are dissolved in 100 grams of water at a temperature of 20 ° C).

EXAMPLE 4 Solubility of lithium phosphate Lithium phosphate (Li3P04) has a relatively low solubility in water (0.038 grams per 100 grams of water at a temperature of 20 ° C). Therefore, it is less preferred for applications in which water (produced water, injection water, or aqueous cleaning fluid) is used to dissolve the particulate residues. However, light acidification, for example, with acetic acid or hydrochloric acid, increases the solubility greatly. For example, LYH2PO is very soluble in water at 55% by weight.

EXAMPLE 5 Fluid formulations for water-based drillingThe following tests refer to water-based drilling fluid formulations. The fluid formulations 1-4 (see table 4 below) are suitable for use as drilling fluids, termination fluids such as a drilling pill or a fluid for widening, a reoperation fluid such as a neutralizing fluid. The fluid formulation 4 represents a typical fluid for drilling the prior art that is currently used in the industry as, for example, a reservoir drilling fluid. This prior art fluid contains water insoluble calcium carbonate solids for reagent and is included for comparative purposes. The properties of fluid formulations 1-4 are provided in the following table 5.

Materials Melamine powder, lithium carbonate, lithium phosphate and potassium chloride were as supplied by Aldrich UK (supplier of laboratory chemicals). DuoVis ™ (rubber viscosifier xanthan), DualFlo ™ (fluid loss reducer based on starch derivative) and Starcarb ™ (calcium carbonate powder) were supplied by M-I Swaco 11c. The fluid formulations are analyzed in accordance with ISO 10416: 2002 (API RP 131 7th edition). The results of fluid loss are also presented in the following table 5 below.

TABLE 4 Fluid Formulations The variation in the gravimetric doses of the powders is to provide approximately the same volume charge as the comparative fluid Starcarb (Fluid A).

TABLE 5 Properties of fluid formulations After the API fluid loss test, excess drilling fluid from the cell used in the test is decanted and replaced with deionized water. The cell is resealed, pressurized to 7.03 kg / cm2 with nitrogen, and the permeation rate is measured through the filter cake for 30 minutes. A similar test is performed by repeating the API fluid loss test to provide new filter cakes from fluids 2 and 4, followed by permeation of deionized water that is pressurized with carbon dioxide to 7.03 kg / cm2. A similar test is performed by repeating the API fluid loss test to provide a filter cake with the fluids on the 4, followed by permeation of 5% acetic acid for 30 minutes, or until all the liquid in the cell passes through. of the filter cake. The results of these additional tests are provide in the following table 6, which shows the average permeation speeds (mls / min).

TABLE 6 Results of the fluid loss test The flow rate of deionized water through the filter cakes containing lithium phosphate and lithium carbonate is clearly improved compared to the reference filter cake containing calcium carbonate (fluid 4). The speeds are still quite slow because the Duovis and DualFlo polymers concentrated in the filter cake reduce the flow rate and therefore the dissolution of the poorly water soluble particles during the brief duration (30 minutes) of the test. The filter cake containing melamine rapidly develops a much higher permeability towards the deionized water. The presence of carbon dioxide increases the Flow rate of water through the filter cake containing lithium carbonate in more than three times. The poorly water soluble solids of the present invention react with 5% acetic acid much faster than particulate calcium carbonate (the industry norm).

EXAMPLE 6 Lost Circulation Material and Lost Circulation Control Fluid Water Based A base sieve is removed from a cell for loss of API fluid and a bed of approximately 2.54 cm of 20-30 mesh sand is placed in the cell. This bed of sand represents an extremely high permeability rock formation. Then water is poured through the bed to wet the sand. A simple drilling fluid is mixed according to the following formulation: Deionized water 330 g Duovis TM 1.5 g DualFlo TM 3.5 g Barite 63 g A portion of this drilling fluid is poured gently into the top of the sand bed. By pressurizing the cell to a pressure of 3,515 kg / cm2, the complete drilling fluid flows immediately through the sand bed in less than 3 seconds. This represents a problem of lost circulation such as could be found in the field. A suspension is obtained by mixing 100 grams of melamine (from Aldrich) in 290 g of water, and pouring 100 ml of the suspension into the cell. When pressurizing to 3,515 kg / cm2 the aqueous phase of the suspension is immediately filtered through the sand bed. When opening the cell a layer of white filter cake of melamine particles is observed above the sand bed. A portion of the "simple" drilling fluid is poured into the cell which is re-pressurized to 3.515 kg / cm2. A much slower flow of the drilling fluid passes through the sand bed, but everything (approximately 100 ml) is still lost from the cell over a period of about 30 seconds. When opening the cell it is observed that the drilling fluid has flowed through a small discontinuity in the bed of the melamine particles. The melamine particles are then added to the drilling fluid remaining at a dose of approximately 35.44 kg / m3. By placing this fluid inside the cell and re-pressurizing to 3,515 kg / cm2, the drilling fluid begins to flow through the sand packing but decelerates to a virtual stop in approximately 5-10 seconds. The pressure increases to 7.03 kg / cm2. The effluent velocity from the cell is then stabilized at a normal, slow filtration rate. This experiment illustrates the use of poorly water soluble solid particles as a material for lost circulation, either in a specially designed fluid that is pumped into place in a bore to control fluid losses, or as an additive to a drilling fluid such as a drilling fluid. The addition of poorly soluble water material to the drilling fluids can be used to stop fluid losses, but it can also be used preventively to prevent the occurrence of such losses. The particle size of the melamine obtained from Aldrich is measured by dry sieving using a vibrating screen shaker. The results in percent in weight are the following: > 500 microns 0.22% < 500 > 300 microns 1.60% < 300 > 150 micras 74.0% < 150 microns 24.2% Said sized particles are quite suitable for sealing the pores in sand formations with extreme permeability, and also for them to accumulate in fractures with a width of less than about 1 mm by rapid filtration of a suspension with a high solids content of the particles that It is flowing into the fracture.

EXAMPLE 7 Oil-based drilling fluid containing melamine particles, and treatment of the filter cake of the same to establish the through flow of sea water An oil-base drilling fluid is prepared, based on the FazePro ™ product from M-I Swaco LLC (see table 7 below). The inverted emulsion of this oil-base drilling fluid is designed to be destabilized after the application of an acid thereby allowing improved cleaning compared to conventional oil-based drilling fluids. The addition of melamine powder provides resizing material and for the filter cake to seal the surface of sand of permeable formations. After drilling, the filter cake can be treated with an acid solution to break up the emulsion within the filter cake in order to increase the permeability of the cake. The acid also begins to dissolve some of the particulate melamine. In the case of a seawater injection well, the acid can be followed by injection of seawater which continues to dissolve the remaining melamine until the residues are completely removed. This example shows that an oil-base drilling fluid with appropriate properties can be formulated for the purpose of drilling with solids for melamine resurfacing. Subsequently, the filter cake is treated with an acid solution followed by the flow of injected seawater, of which both fluids are active to remove the seal that was provided by the filter cake. The oil-base drilling formulation is mixed using a Silverson L4RT mixer equipped with a high shear head. The mixing times per component are shown in the following table 7. The speed of the mixer is approximately 6000 rpm. The temperature is monitored thoroughly and maintained at 65.56 ° C or less by the use of a water bath for cooling.

TABLE 7 (a) of TotalFinaElf UK Limited (b) of Trademark M-I Swaco 11c After mixing, the oil-based drilling fluid is hot-rolled at a temperature of 65.56 ° C for 16 hours to simulate low hole heating in the field. The viscous properties and the fluid loss at high temperature / high pressure (HTHP FL) are then measured and are given in the following table 8.

TABLE 8 TABLE 8 (with The results presented in table 8 show that satisfactory rheological and filtration performance is obtained. After the HTHP fluid loss test, excess drilling fluid is drained from the cell and replaced with a 5% glacial acetic acid solution in kerosene. The cell is closed and heated to a temperature of 45 ° C. The acid solution is then pressurized to 7.03 kg / cm2 for the solution to permeate through the filter cake, the weight of the flow through time is measured, as recorded later in Table 9.

TABLE 9 Permeation of the acid solution through the cake The cell is then filled again with seawater and heated to a temperature of 45 ° C. When pressurized to 7.03 kg / cm2, the seawater quickly passes through the filter cake (66.5 g in 17 seconds). The evaluation of the filter cake shows that irregular areas have been leached leaving some white melamine residues. The residues of the filter cake on the filter paper are placed in 500 ml of seawater and kept at a temperature of 45 ° C for 72 hours. After this time no visible melamine particles remain. This is very convenient for seawater injection wells in which seawater injection is normally continued for years, leaving little opportunity for any melamine filter cake residual remains undissolved. Therefore, it is maximum seawater injection capacity.

Claims (27)

NOVELTY OF THE INVENTION Having described the present invention, it is considered as a novelty and therefore the content of the following is claimed as property: CLAIMS

1. - A drilling fluid comprising a base fluid and a particulate for resizing consisting of a material poorly soluble in water that is selected from the group consisting of melamine (2,4,5-triamino-1,3,5- triazine), lithium carbonate, lithium phosphate (Li3P04), and magnesium sulphite.

2. A drilling fluid according to claim 1 characterized in that the base fluid is present in the drilling fluid in an amount in the range of about 30 to 99% by weight of the fluid.

3. - A drilling fluid according to claim 1 or 2, characterized in that the particulate for poorly water-soluble dressing is present in the drilling fluid in an amount in the range of 1 to 70% by weight.

4. - A drilling fluid in accordance with any of the preceding claims, characterized in that the drilling fluid is a fluid for drilling, maintenance or termination and the particulate for poorly water-soluble dressing has a particle size distribution in the range of about 0.1 microns to 600 microns.

5. A drilling fluid according to any of the preceding claims, characterized in that the drilling fluid is an aqueous-based fluid and the drilling fluid comprises at least one additional additive which is selected from the group consisting of viscosifiers, weighting agents, water-soluble salts that increase density, agents for filtration control or loss of fluid, agents for pH control, hydration inhibitors of clay or shale, bactericides, surfactants, solid and liquid lubricants, inhibitors of gas hydrate, corrosion inhibitors, defoamers, scale inhibitors, emulsified hydrophobic liquids such as oils, acid gas scrubbers (such as hydrogen sulphide scrubbers), thinners (such as lignosulfonates), and de-emulsifiers.

6. - A fluid for drilling according to claim 5, characterized in that the fluid for Water-borne perforation comprises an agent for fluid loss control which is selected from the group consisting of water soluble polymers, lignites, modified lignites, and entangled lignosulfonates.

7. A drilling fluid according to any of claims 1 to 4, characterized in that the drilling fluid is an oil-based fluid comprising at least one additional additive that is selected from the group consisting of viscosifiers, surfactants (to form stable water-in-oil emulsions and to impregnate with oil the surface of mineral weighting agents), additives for fluid loss control, lubricants (solids and liquids), and acid gas scrubbers (for example, scrubbers). hydrogen sulfide) .

8. A method for forming a removable filter cake on the walls of a perforation that penetrates a porous and permeable rock formation comprising the steps of: (a) placing a drilling fluid in the perforation in which the fluid for The perforation comprises a base fluid and a particulate for resizing consisting of a slightly water soluble material which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate (Li3P04), and sulfite magnesium, preferably, melamine and lithium carbonate; Y (b) allowing the particulate to be deposited to be deposited from the drilling fluid on and / or into the perforation walls to form the removable filter cake, thereby reducing the loss of fluid to the formation through of the filter cake.

9. - A method according to claim 8, characterized in that an additive is included for control of fluid loss in the drilling fluid.

10. - A method according to claim 8 or 9, characterized in that the particulate agent for poorly soluble resoiling in water is eliminated by placing the well in production.

11. - A method according to claim 8 or 9, characterized in that the particulate agent for poorly soluble resoiling in water is eliminated from the perforation of an injection well by dissolving in the water that is injected into the injection well.

12. - A method according to claim 8 or 9, characterized in that the particulate for poorly soluble water-soluble resin is removed by (a) placing a downstream cleaning fluid and (b) leaving the cleaning fluid to soak through the perforation range where it is desired to remove the filter cake for a sufficient period of time either to completely dissolve the dressing agent or to solubilize the dressing agent to the extent that that the particles are of a sufficiently small size to allow their removal from the formation.

13. - A method according to claim 12, characterized in that the cleaning fluid is an aqueous fluid that is sub-saturated with respect to the agent for res- toration or is an aqueous solution of an acid or a precursor of a weak acid.

14. - A method according to claim 12, characterized in that the particulate for water-poor resin is composed of magnesium sulphite, and the cleaning fluid comprises an aqueous solution of an oxidizing agent that can convert magnesium sulphite in water-soluble magnesium sulfate.

15. A method according to claim 12 or 13, characterized in that the particulate agent for water-poor re-soldering is constituted by melamine, and the removable filter cake is removed from the walls of a perforation by placing an aqueous fluid for washing hole down and allowing that the washing fluid soaks the perforation interval where it is desired to remove the filter cake for a period of time sufficient for the washing fluid to be heated to a temperature of at least 60 ° C and allowing the washing fluid hot soak the interval either until the particulate for resoiling is completely dissolved in the washing fluid or is solubilized to the extent that the particles are of sufficiently small size to allow their removal from formation.

16. A method for drilling a perforation through a porous and permeable rock formation using a drilling fluid comprising a base fluid, an additive for control of fluid loss, and a particulate for resizing constituted by a little material soluble in water which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate (Li3P04), and magnesium sulphite characterized by maintaining the pressure of the drilling fluid in the bore above the pressure in the formation of porous and permeable rock in such a way that a filter cake is deposited on and / or in the walls of the perforation and reduces the loss of fluid from the drilling fluid towards the formation of rock. 17.- A drilling method in accordance with the claim 16, characterized in that the drilling fluid is as defined in any of claims 4 to 7. 18.- A method for controlling the loss of fluid from an internal piercing of a porous and permeable rock formation through a conduit. of high conductivity extending from the perforation to the interior of the rock formation comprising the steps of: (a) placing a fluid for circulation lost in the perforation characterized in that the fluid for lost circulation comprises a suspension of material for particulate lost circulation (LCM) in a base fluid in which the LCM is suspended in the base fluid in an amount of at least 14,175 kg / m3, preferably at least 28.35 kg / m3, more preferred, at least 56.7 kg / m3 , and even more preferred at least 85.05 kg / m3, and is constituted by a poorly soluble material in water which is selected from the group consisting of melamine, carbonate lithium, lithium phosphate (LÍ3PO4), and magnesium sulphite; and (b) allow the LCM to accumulate in the high conductivity duct whereby a removable low permeability plug is formed which overlies the duct thereby reducing the loss of fluid to the formation through of the conduit. 19. - A method according to claim 18, characterized in that an agent for fluid loss control is present in the suspension thereby helping to seal the high conductivity duct. 20. - A method according to claim 18 or 19, characterized in that the base fluid is a drilling fluid. 21. A method for controlling the loss of fluid from a termination fluid into a porous and permeable rock formation penetrated by a perforation: (a) by placing a termination fluid in the perforation characterized in that the termination fluid comprises a base fluid, an additive for control of fluid loss, and a particulate for resizing consisting of a poorly soluble material in water that is selected from the group consisting of melamine, lithium carbonate, lithium phosphate, and magnesium sulfite; and (b) maintaining the pressure of the termination fluid in the bore above the pore pressure of the rock formation such that a filter cake is deposited on or on the walls of the rock. perforation 22. - A method according to claim 21, characterized in that the termination fluid is as defined in any of claims 4 to 7. 23. - A method according to claim 21 or 22, characterized in that the fluid of The termination additionally contains a polymeric viscosifying agent or agents such as xanthan gum, hydroxyethylcellulose, "welan" gum (e.g., Biozan ™, from Kelco) or diutan gum (e.g., Geovis XT ™; from Kelco). 24. - A method for controlling the loss of fluid from a reoperation fluid to a range of a perforation that lies through a porous and permeable rock formation characterized in that the method comprises the steps of: (a) pumping a sufficient volume of a first reoperation fluid to fill the perforation range that lies through the porous and permeable rock formation in which the first reoperation fluid comprises a base fluid, an additive for fluid loss control, and an agent particulate for dressing consisting of a sparingly soluble material in water that is selected from the group consisting of melamine, lithium carbonate, lithium phosphate, and magnesium sulphite in such a way that a removable filter cake is deposited from the first reoperation fluid in said perforation interval on the walls of the perforation and into any cracks, fractures or cracks in it; (b) pumping a second reoperation fluid into the borehole in which the second reoperation fluid is substantially saturated with the material poorly soluble in water and has a density sufficient to at least counteract the pressure of the porous rock formation and permeable; and wherein the filter cake deposited in step (a) reduces the loss of fluid from the reoperation fluids to the formation of porous and permeable rock. 25. A method for fracturing a porous and permeable rock formation comprising: injecting a fracturing fluid within a range of a perforation through the rock formation to be fractured characterized in that the fracturing fluid comprises a fluid base, support agent, a viscosifier, and an agent for particulate runoff control constituted by a poorly water soluble material that is selected from the group consisting of melamine, lithium carbonate, lithium phosphate, and magnesium sulphite; and maintaining the pressure of the fracturing fluid in the perforation range through the formation of rock above the fracture pressure of the formation with which the support agent enters and keeps open the fractures that form in the wall of the perforation and the agent for particulate runoff control seals the exposed pore grooves in the walls of the fracture. 26.- A method to divert non-acidic treatment fluids away from high permeability rock formations or high conductivity ducts and into lower and / or partially clogged permeability rock formations or lower conductivity ducts using a fluid of treatment comprising a non-acidic fluid and a particulate for resizing consisting of a sparingly soluble material in water which is selected from the group consisting of melamine, lithium carbonate, lithium phosphate (Li3P04), and magnesium sulphite. 27. A method according to claim 26, characterized in that the non-acidic fluid is an aromatic solvent and the treatment fluid is pumped into a perforation for hydrocarbon production in such a way that a filter cake is formed on and / or in a high permeability rock formation and / or the particulate agent for sealing between and sealing the high conductivity ducts (or flow channels) in the walls of the perforation, thereby limiting the loss of aromatic solvent from the perforation, thereby diverting the aromatic solvent towards low conductivity ducts (or flow channels) that are damaged by deposits of asphaltene and / or wax, thereby improving the dissolution of the deposits by the aromatic solvent.