Classifications

• • 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
  • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
• • 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
  • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
• • 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
  • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
  • C09K2208/26—Gel breakers other than bacteria or enzymes

Definitions

• Embodiments relate generally to wellbore fluids. More specifically, embodiments relate to displacement and chemical breaker fluids.
• various fluids are typically used in the well for a variety of functions.
• the fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface.
• the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
• the drilling fluid takes the form of a “mud,” i.e., a liquid having solids suspended therein.
• the solids function to impart desired rheological properties to the drilling fluid and also to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well.
• the drilling mud may be either a water-based or an oil-based mud.
• Drilling muds may consist of polymers, biopolymers, clays and organic colloids added to a water-based fluid to obtain the required viscous and filtration properties. Heavy minerals, such as barite or calcium carbonate, may be added to increase density. Solids from the formation are incorporated into the mud and often become dispersed in the mud as a consequence of drilling. Further, drilling muds may contain one or more natural and/or synthetic polymeric additives, including polymeric additives that increase the rheological properties (e.g., plastic viscosity, yield point value, gel strength) of the drilling mud, and polymeric thinners and flocculents.
• rheological properties e.g., plastic viscosity, yield point value, gel strength
• Polymeric additives included in the drilling fluid may act as fluid loss control agents.
• Fluid loss control agents such as starch, prevent the loss of fluid to the surrounding formation by reducing the permeability of filter cakes formed on the newly exposed rock surface.
• polymeric additives are employed to impart sufficient carrying capacity and thixotropy to the mud to enable the mud to transport the cuttings up to the surface and to prevent the cuttings from settling out of the mud when circulation is interrupted.
• Many drilling fluids may be designed to form a thin, low-permeability filter cake to seal permeable formations penetrated by the drill bit.
• the filter cake is essential to prevent or reduce both the loss of fluids into the formation and the influx of fluids present in the formation.
• the filter cake may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore.
• Filter cakes often comprise bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates.
• One feature of a drilling fluid is to retain these solid and semi-solid particles as a stable suspension, free of significant settling over the time scale of drilling operations.
• the selection of the type of drilling fluid to be used in a drilling application involves a careful balance of both the good and bad characteristics of the drilling fluids in the particular application and the type of well to be drilled.
• the primary benefits of selecting an oil-based drilling fluid, also known as an oil-based mud include: superior hole stability, especially in shale formations, formation of a thinner filter cake than the filter cake achieved with a water-based mud, excellent lubrication of the drilling string and downhole tools, and penetration of salt beds without sloughing or enlargement of the hole, as well as other benefits that should be known to one of skill in the art.
• oil-based muds are their excellent lubrication qualities. These lubrication properties permit the drilling of wells having a significant vertical deviation, as is typical of off-shore or deep water drilling operations or when a horizontal well is desired. In such highly deviated holes, torque and drag on the drill string are a significant problem because the drill pipe lies against the low side of the hole, and the risk of pipe sticking is high when water-based muds are used. In contrast, oil-based muds provide a thin, slick filter cake that helps to prevent pipe sticking, and thus the use of the oil-based mud can be justified.
• Oil-based muds typically contain some water, either from the formulation of the drilling fluid itself, or water may be intentionally added to affect the properties of the drilling fluid or mud.
• water-in-oil type emulsions also known as invert emulsions
• an emulsifier is used to stabilize the emulsion.
• the invert emulsion may contain both water soluble and oil soluble emulsifying agents.
• Typical examples of such emulsifiers include polyvalent metal soaps, fatty acids and fatty acid soaps, and other similar suitable compounds that should be known to one of ordinary skill in the art.
• filter cake formation is essential to drilling operations, the filter cake can be a significant impediment to the production of hydrocarbon or other fluids from the well if, for example, the rock formation is plugged by the filter cake. Because filter cake is compact, it often adheres strongly to the formation and may not be readily or completely flushed out of the formation by fluid action alone.
• the removal of filter cake has been conventionally achieved with water-based treatments that include: an aqueous solution with an oxidizer (such as persulfate), a hydrochloric acid solution, organic (acetic, formic) acid, combinations of acids and oxidizers, and aqueous solutions containing enzymes.
• an oxidizer such as persulfate
• a hydrochloric acid solution organic (acetic, formic) acid
• combinations of acids and oxidizers e.g., formic acid
• aqueous solutions containing enzymes e.g., the use of enzymes to remove filter cake is disclosed in U.S. Pat. No. 4,169,818.
• Chelating agents e.g., EDTA
• the oxidizer and enzyme attack the polymer fraction of the filter cake and the acids typically attack the carbonate fraction (and other minerals).
• oxidizers and enzymes are ineffective in breaking up the carbonate portion, and acid are ineffective on the polymer portions.
• a clean-up solution would ideally include hydrochloric acid, which reacts very quickly with calcium carbonate.
• hydrochloric acid reacts very quickly with calcium carbonate.
• a strong acid is also reactive with any calcium carbonate in the formation (e.g., limestone), and can permeate into the formation.
• the fluids disclosed in these references all contain one form or another of an ethoxylated tertiary amine compound that stabilizes the invert emulsion when it is not protonated. Upon protonation of the amine compound, the invert emulsion reverses and becomes a regular emulsion. In most cases, deprotonation of the amine compound allows for the reformation of an invert emulsion.
• the clean-up of wells drilled with this invert emulsion drilling fluid may be simplified by using a wash fluid that contains acid in a concentration sufficient to protonate the amine surfactant in the drilling fluid (and hence the filter cake).
• the presence of the amine surfactant in this drilling fluid may control the phase state (i.e., invert versus regular emulsions) of the fluids in the well.
• U.S. Pat. No. 5,888,944 describes the use of an acid sensitive surfactant that stabilizes the invert emulsion of the drilling fluid.
• the surfactant Upon the addition of an acid in a wash fluid, for example, the surfactant immediately protonates to break or invert the invert emulsion to an oil-in-water type emulsion.
• the present invention relates to a method of cleaning a wellbore prior to the production of oil or gas, wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake.
• the method may include circulating a breaker fluid into the wellbore, where the breaker fluid includes a non-oleaginous internal phase and an oleaginous external phase, where the non-oleaginous phase includes a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid, and a weighting agent, and the oleaginous external phase includes an oleaginous fluid and an emulsifier, and where the hydrolysable ester is selected so that upon hydrolysis an organic acid is released and the invert emulsion of the filter cake breaks.
• the present invention relates to a method of producing a hydrocarbon from a formation.
• the method may include the steps of drilling the formation with an invert emulsion drilling mud, performing at least one completion operation in the wellbore, emplacing a breaker fluid in the wellbore, where the breaker fluid includes a non-oleaginous internal phase and an oleaginous external phase, where the non-oleaginous phase includes a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid, and a weighting agent, and the oleaginous external phase includes an oleaginous fluid and an emulsifier, and shutting the well for a predetermined time to allow the hydrolysis of the ester and the breaking of the invert emulsion filter cake.
• the present invention relates to a solution that includes a non-oleaginous internal phase and an oleaginous external phase, where the non-oleaginous phase includes a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid, and a weighting agent, and the oleaginous external phase includes an oleaginous fluid and an emulsifier.
• embodiments disclosed herein are generally directed to chemical breaker and displacement fluids that are useful in the drilling, completing, and working over of subterranean wells, preferably oil and gas wells.
• the displacement and completion fluids may be selected from a water based fluid and an invert emulsion fluid.
• the usefulness of the fluids disclosed herein is not dependent on the use of ethoxylated tertiary amines in the fluids used to drill the well. Thus, the broad applicability and usefulness of the fluids disclosed herein is greatly enhanced.
• the water-based and invert emulsion displacement and completion fluids of the present invention are particularly useful in wells that are drilled with an invert emulsion drilling fluid that forms an invert emulsion filter cake in the well.
• the breaker fluid may be an invert emulsion fluid that may include a non-oleaginous internal phase and an oleaginous external phase.
• the non-oleaginous internal phase may include a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid; and optionally a weighting agent such as a high density brine solution.
• the oleaginous external phase may include an oleaginous fluid such as diesel or other suitable hydrocarbon or synthetic oil, and an emulsifier.
• other components may include a viscosifying agent, a wetting agent, and a cleaning agent.
• the oleaginous fluid used for formulating the invert emulsion fluids used in the practice of the present invention are liquids and are more preferably a natural or synthetic oil and more preferably, the oleaginous fluid is selected from the group including diesel oil, mineral oil, such as polyolefins, polydiorganosiloxanes, siloxanes or organo-siloxanes, and mixtures thereof.
• the concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion. However, generally the amount of oleaginous fluid must be sufficient to form a stable emulsion when utilized as the continuous phase.
• the amount of oleaginous fluid at least about 30 percent, preferably at least about 40 percent, and more preferably at least about 50 percent by volume of the total fluid. In one embodiment, the amount of oleaginous fluid is from about 30 to about 95 percent by volume and more preferably from about 40 to about 90 percent by volume of the invert emulsion fluid.
• the non-oleaginous fluid also used in the formulation of the invert emulsion fluids is a liquid and preferably is an aqueous liquid. More preferably, the non-oleaginous fluid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof.
• the amount of the non-oleaginous fluid is typically less than the theoretical limit needed for forming an invert emulsion. In various embodiments, the amount of non-oleaginous liquid is at least about 1, preferably at least about 5, and more preferably greater than about 10 percent by volume of the total fluid.
• the amount of the non-oleaginous fluid should not be so great that it cannot be dispersed in the oleaginous phase.
• the amount of non-oleaginous fluid is less than about 70% by volume and preferably from about 1% to about 70% by volume.
• the non-oleaginous fluid is preferably from about 10% to about 60% by volume of the invert emulsion fluid.
• the breaker fluid may be a water based fluid that may include an aqueous fluid.
• the water based fluid may include a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid; and optionally a weighting agent such as a high density brine solution.
• the aqueous fluid used in the water based fluids may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof.
• the water soluble polar organic solvent should be at least partially soluble in a oleaginous fluid, but should also have partial solubility in an aqueous fluid.
• the polar organic solvent component of the present invention may be a mono-hydric, di-hydric or poly-hydric alcohol or a mono-hydric, di-hydric, or poly-hydric alcohol having poly-functional groups.
• Examples of such compounds include aliphatic diols (i.e., glycols, 1,3-diols, 1,4-diols, etc.), aliphatic poly-ols (i.e., tri-ols, tetra-ols, etc.), polyglycols (i.e., polyethylenepropylene glycols, polypropylene glycol, polyethylene glycol, etc.), glycol ethers (i.e., diethylene glycol ether, triethylene glycol ether, polyethylene glycol ether, etc.) and other such similar compounds that may be found useful in the practice of the present invention.
• diols i.e., glycols, 1,3-diols, 1,4-diols, etc.
• polyglycols i.e., polyethylenepropylene glycols, polypropylene glycol, polyethylene glycol, etc.
• glycol ethers i.e., diethylene glycol
• the water soluble organic solvent is a glycol or glycol ether, such as ethylene glycol mono-butyl ether (EGMBE).
• GMBE ethylene glycol mono-butyl ether
• Other glycols or glycol ethers may be used in the present invention so long as they are at least partially miscible with water.
• the hydrolysable ester should be selected so that the time to achieve hydrolysis is predetermined on the known downhole conditions, such as temperature. It is well known in the art that temperature, as well as the presence of a hydroxide ion source, has a substantial impact on the rate of hydrolysis of esters. For a given acid, for example formic aid, one of skill in the art can conduct simple studies to determine the time to hydrolysis at a given temperature. It is also well known that as the length of the alcohol portion of the ester increases, the rate of hydrolysis decreases.
• the hydrolysable ester of a carboxylic acid is a formic acid ester of a C4 to C30 alcohol.
• the hydrolysable ester of the carboxylic acid comprises from about 5 to 50 volume percent of a water-based breaker fluid, and preferably from about 20 to 40 volume percent.
• the hydrolysable ester of the carboxylic acid comprises from about 20 to about 60 volume percent of an invert emulsion-based breaker fluid, preferably, greater than 30 volume percent.
• a suitable hydrolysable ester of a carboxylic acid is available from Shrieve Chemical Group (The Woodlands, Tex.) under the name Break-910.
• the weighting agent is preferably a high density brine containing salts of alkali and alkaline earth metals.
• brines formulated with high concentrations of sodium potassium, or calcium salts of the halides, formate, acetate, nitrate, and the like; cesium salts of formate, acetate, nitrate, and the like, as well as other compounds that should be well known to one of skill in the art can be used as solids free weighting agents.
• the selection of a weighting agent may partially depend the desired density of the breaker fluid, as known by one of ordinary skill in the art.
• the emulsifier used in the invert emulsion breaker fluid should be selected so as to form a stable invert emulsion that breaks with time and/or upon hydrolysis of the ester.
• the emulsifier's hydrophilic-lipophilic balance (HLB) value is sufficiently shifted to destabilize the invert emulsion.
• the HLB value indicates the polarity of the molecules in a range of 1 to 40 that increases with increasing hydrophilicity of the emulsifier.
• Preferred emulsifiers may include VERSAWETTM and VERSACOATTM, which are commercially available from M-I L.L.C., Houston, Tex.
• an amine-based acid sensitive emulsifier such as those described in U.S. Pat. No. 6,218,342, 6,790,811, and 6,806,233, the contents of which are incorporated by reference herein, may be used.
• Both the invert emulsion fluids and water based fluids of the present invention may further contain additional chemicals depending upon the end use of the fluid so long as they do not interfere with the functionality of the fluids (particularly the emulsion when using invert emulsion displacement fluids) described herein.
• additional chemicals for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents may be added to the fluid compositions of this invention for additional functional properties.
• wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents may be added to the fluid compositions of this invention for additional functional properties.
• the addition of such agents should be well known to one of ordinary skill in the art of formulating drilling fluids and muds.
• Wetting agents that may be suitable for use in this invention include crude tall oil, oxidized crude tall oil, surfactants, organic phosphate esters, modified imidazolines and amidoamines, alkyl aromatic sulfates and sulfonates, and the like, and combinations or derivatives of these.
• the use of fatty acid wetting agents should be minimized so as to not adversely affect the reversibility of the invert emulsion disclosed herein.
• Faze-WetTM, VersaCoatTM, SureWetTM, VersawetTM and VersawetTM NS are examples of commercially available wetting agents manufactured and distributed by M-I L.L.C. that may be used in the fluids disclosed herein.
• Silwet L-77, L-7001, L7605, and L-7622 are examples of commercially available surfactants and wetting agents manufactured and distributed by General Electric Company (Wilton, CT).
• Organophilic clays may be useful as viscosifiers and/or emulsion stabilizers in the fluid composition of the present invention.
• Other viscosifiers such as oil soluble polymers, polyamide resins, polycarboxylic acids and soaps can also be used.
• the amount of viscosifier used in the composition can vary upon the end use of the composition. However, normally about 0.1 % to 6% by weight range is sufficient for most applications.
• VG-69TM and VG-PLUSTM are organoclay materials distributed by M-I, L.L.C., Houston, Tex., and Versa-HRPTM is a polyamide resin material manufactured and distributed by M-I, L.L.C., that may be used in this invention.
• the viscosity of the displacement fluids is sufficiently high such that the displacement fluid may act as its own displacement pill in a well.
• Suitable thinners that may be used in the breaker fluids disclosed herein include, for example, lignosulfonates, modified lignosulfonates, polyphosphates, tannins, and low molecular weight polyacrylates. Thinners are typically added to a drilling fluid to reduce flow resistance and control gelation tendencies. Other functions performed by thinners include reducing filtration and filter cake thickness, counteracting the effects of salts, minimizing the effects of water on the formations drilled, emulsifying oil in water, and stabilizing mud properties at elevated temperatures.
• cleaning agents in the fluids disclosed herein should be well known to one of skill in the art.
• a wide variety of synthetic and natural product derived cleaning agents may be used.
• a common natural product derived cleaning agent is d-limonene.
• the cleaning ability of d-limonene in well drilling applications is disclosed in U.S. Pat. No. 4,533,487, and in combination with various specialty surfactants in U.S. Pat. No. 5,458,197, the contents of which are incorporated herein.
• the methods used in preparing both the water-based and invert emulsion breaker fluids utilized in the methods of the present disclosure are not critical.
• conventional methods can be used to prepare the invert emulsion fluids in a manner analogous to those normally used to prepare oil-based drilling fluids.
• a desired quantity of oleaginous fluid such as diesel oil
• the internal non-oleaginous phase is prepared by combining the polar organic co-solvent and the hydrolysable ester into the selected brine with continuous mixing.
• An invert emulsion of the present invention is formed by vigorously agitating, mixing, or shearing the oleaginous fluid and the non-oleaginous fluid.
• breaker fluids disclosed herein may also be used in various embodiments as a displacement fluid and/or a wash fluid.
• a displacement fluid is typically used to physically push another fluid out of the wellbore
• a wash fluid typically contains a surfactant and may be used to physically and chemically remove drilling fluid reside from downhole tubulars.
• a breaker fluid may be in a method of cleaning a wellbore that has been drilled with an invert emulsion drilling mud, and thus has an invert emulsion filter cake formed thereon.
• the breaker fluid may be circulated into the wellbore, contacting the invert emulsion filter cake.
• the hydrolysable ester contained within the breaker fluid may hydrolyze to release an organic acid and break the invert emulsion of the filter cake.
• the breaker fluid may be circulated in the wellbore that has not produced any hydrocarbons.
• a breaker fluid of the present invention may be used to clean the wellbore.
• water-based breaker fluid and/or the invert emulsion breaker fluid may also be used as a displacement fluid to push fluids out of a wellbore.
• An invert emulsion breaker fluid may act as a push pill or displacement fluid to effectively displace the invert emulsion drilling mud.
• a water based breaker fluid may act as a displacement fluid to effectively displace brine from the wellbore.
• the water-based breaker fluid and/or invert emulsion breaker fluid may further be used as a wash fluid to physically and/or chemically remove the invert emulsion filter cake once the filter cake has been disaggregated by the breaker system.
• a breaker fluid (either a water-based or an invert emulsion fluid) disclosed herein may be used in the production of hydrocarbons from a formation. Following the drilling of a formation with an invert emulsion drilling mud, at least one completion operation may be performed on the well. A breaker fluid may then be circulated in the well, and the well may be shut for a predetermined time to allow the hydrolysis of the ester and the breaking of the invert emulsion of the filtercake formed from the drilling mud. In another embodiment, formation fluids may then enter the well and production of the formation fluids may ensue.
• the breaker fluid may be circulated in the wellbore during or after the performance of the at least one completion operation. In other embodiments, the breaker fluid may be circulated either after a completion operation or after production of formation fluids has commenced to destroy the integrity of and clean up residual conventional or reversible invert emulsion fluids remaining inside casing or liner.
• completion processes may include one or more of the strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and installing the proper completion equipment to ensure an efficient flow of hydrocarbons out of the well or in the case of an injector well, to allow for the injection of gas or water.
• a breaker fluid as disclosed herein may be used in a cased hole to remove any residual oil based mud left in the hole during any drilling and/or displacement processes.
• Well casing may consist of a series of metal tubes installed in the freshly drilled hole. Casing serves to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out of the well hole as it is brought to the surface, and to keep other fluids or gases from seeping into the formation through the well.
• Completion operations may specifically include open hole completions, conventional perforated completions, sand exclusion completions, permanent completions, multiple zone completions, and drainhole completions, as known in the art.
• a completed wellbore may contain at least one of a slotted liner, a predrilled liner, a wire wrapped screen, an exapandable screen, a sand screen filter, a open hole gravel pack, or casing.
• Another embodiment of the present invention involves a method of cleaning up a well bore drilled with the invert emulsion drilling fluid described above.
• the method involves circulating a breaker fluid disclosed herein, in a wellbore, which as been drilled to a larger size (i.e., under reamed) with an invert emulsion drilling mud, and then shutting in the well for a predetermined amount of time to allow the hydrolysis of the ester to take place.
• the invert emulsion breaks, thus forming two phases, and oil phase and a water phase. These two phases can be easily produced from the well bore upon initiation of production and thus the residual drilling fluid is easily washed out of the well bore.
• the fluids disclosed herein may also be used in a wellbore where a screen is to be put in place down hole. After a hole is under-reamed to widen the diameter of the hole, drilling string may be removed and replaced with production tubing having a desired sand screen. Alternatively, an expandable tubular sand screen may be expanded in place or a gravel pack may be placed in the well. Breaker fluids may then be placed in the well, and the well is then shut in to allow for the hydrolysis of the ester to take place.
• the invert emulsion breaks thus forming two phases, an oil phase and a water phase. These two phases can be easily produced from the wellbore upon initiation of production and thus the residual drilling fluid is easily washed out of the wellbore.
• the amount of delay between the time when a breaker fluid according to the present invention is introduced to a well drilled with an invert emulsion drilling fluid and the time when the hydrolysable ester of a carboxylic acid hydrolyzes, releasing acid to break the invert emulsion filter cake may depend on several variables.
• the rate of hydrolysis of the hydrolysable ester may be dependent upon the downhole temperature, concentration, pH, amount of available water, filter cake composition, etc. In one embodiment, there may be preferable a downhole temperature of less than 270° F. for the applicability of the displacement fluids of the present invention in a given well.
• the breaker fluid formulation and thus the fluid's chemical properties may be varied so as to allow for a desirable and controllable amount of delay prior to the breaking of invert emulsion filter cake for a particular application.
• the amount of delay for an invert emulsion filter cake to be broken with a water-based displacement fluid according to the present invention may be greater than 1 hour. In various other embodiments, the amount of delay for an invert emulsion filter cake to be broken with a water-based displacement fluid according to the present invention may be greater than 3 hours, 5 hours, or 10 hours.
• the amount of delay for an invert emulsion filter cake to be broken with an invert emulsion displacement fluid may be greater than 15 hours. In various other embodiments, the amount of delay for an invert emulsion filter cake to be broken with an invert emulsion displacement fluid may be greater than 24 hours, 48 hours, or 72 hours.
• the above invert emulsion drilling fluid was heat aged by hot rolling for 16 hours at 196° F. and exhibited the properties shown in Table 2.
• Table 2 The properties listed in Table 2, TABLE 2 Heat-aged @ 196° F.-16 hrs - Rheology @ 120° F. 600 RPM 44 300 RPM 24 200 RPM 17 100 RPM 10 6 RPM 3 3 RPM 3 Gels 10′′ 5 lbs/100 ft 2 Gels 10′ 12 lbs/100 ft 2 Plastic Viscosity 20 cP Yield Point 4 cP Electrical Stability 293 volts
• the initial flow of a fritted alumina filter disk (35 micron) was determined using 200 ml of diesel at 20 psig. A filter cake was then built on to the filter disk by application of the above fluid under pressure at 500 psig and 196° F. for 4 hours. The excess drilling fluid was decanted. About 40 ml of the breaker fluid was gently applied so as to not disturb the filter cake. A pressure of 500 psig was applied and the effluent (if any) was collected and returned to the cell. A soak period was conducted for 16 hours at 196° F. and 100 psig after which the residual breaker was decanted. The return flow of the fritted alumina filter disk (35 micron) was determined using 200 ml of diesel at 20 psig. The percent return flow rate was determined relative to the measured initial flow rate.
• An invert emulsion breaker fluid illustrative of the present disclosure was formulated and compared to diesel and 10% HCl aqueous acid.
• the breaker fluid was formulated as indicated below in Table 3.
• TABLE 3 Component Amount Diesel 60 ml Break-910 30 ml Ethylene glycol mono-butyl ether (5% v/v) 10 ml
• breakers formulated in accordance with the present invention achieve a return flow much greater than either a straight acid wash (10% HCl) or diesel wash. Similar or better results can be achieved using the amine-based surfactants disclosed above.
• a reversible invert emulsion drilling mud was formulated having the following components, all of which are commercially available, as shown below in Table 5.
• Filter cakes built from the above reversible invert emulsion drilling fluid were subjected to a modified High Temperature High Pressure (HTHP) Filtration test.
• the HTHP Filtration test uses a HTHP cell fitted with a fritted disc as a porous medium, on which a filter cake is built.
• the filter cakes were built on 35 micron disks.
• effluent was collected as shown in Table 7.
• Displacement fluids 1 and 2 formulated as shown in Table 8 were added to filter cake Disks 1 and 2, formulated as shown in Table 5, and subjected to a modified HTHP Filtration test.
• Fluid 2 of Table 8 the calcium carbonate was added to the fluid immediately prior to adding the fluid to the filter cake.
• effluent was collected as shown in Table 9 below.
• Table 9 When a steady stream of effluent resulted as being passed through the disk, fresh displacement fluid was added. From Table 9, it can be observed that Fluid 1 achieved a complete break-through of the filtrate after between the 29.5 and 43.5 hour collections.
• Filter cakes built from the invert emulsion drilling fluid, formulated as shown in Table 10 were built on disks (3a-3c) and subjected to a modified HTHP Filtration test.
• Filters cakes built from FazeproTM, a reversible invert emulsion drilling fluid, commercially available from M-I, L.L.C. (Houston, Texas) were also built on disks (4a-4c) and subjected to the modified HTHP Filtration Test.
• effluent was collected as shown in Table 12.
• Displacement breaker fluids 3 and 4 formulated as shown in Table 13, were added to filter cakes disks 3a-3c and 4a-4c, formulated as shown in Table 10, and subjected to a modified HTHP Filtration test.
• fluids of the present invention may be in used in a variety of well applications.
• the fluids of the present invention may be used in both producing and injection wells, and may have further application in remedial clean-up of wells.
• the present invention provides for a wellbore fluid that may break the emulsion of an invert emulsion filter cake and effectively remove such invert emulsion filter cake without inflicting damage on the surrounding formation.
• Displacement and completion fluids according to the present invention may exhibit high-viscosity indices such that they may behave as a high viscosity pill in the well completion process. Furthermore, a delay in the dissolution of the filter cake may be achieved by controlling the effectiveness and reactivity of the chemical breakers.
• the chemical properties of the displacement and breaker fluids disclosed herein may allow for the degradation of the emulsion of the invert emulsion filter cake and the dissolution of acid soluble bridging materials in the filter cake. Additionally, displacement and breaker fluids disclosed herein may be effectively used with either conventional invert emulsion or reversible invert emulsion drilling fluid filter cakes.

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• 2006
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