Solids-Free Wellbore Fluid

The present invention relates to (a) solids-free, non-aqueous wellbore fluids of variable high density, (b) methods for improving the quality of the solids-free, non-aqueous wellbore fluids, (c) invert emulsion wellbore fluids, (d) methods for using the foregoing wellbore fluids during or after drilling to (i) complete and/or treat a production or injection well or (ii) treat and/or modify a subterranean formation, and (e) natural resource systems containing such wellbore fluids. (As used in the specification and claims, the term "wellbore fluid" means a fluid used while conducting pay zone drilling, underreaming, drilling in, plugging back, sand control, perforating, gravel packing, chemical treatment, hydraulic fracturing, cleanout, well killing, tubing and hardware replacement, and zone selective operations as well as a fluid employed as a packer fluid. The term "solids-free" is applied to the basic wellbore fluid having the desired specific gravity. As understood in the art, the term "solids-free" means that no solid material (e.g., weighting agents, viscosifiers, fluid loss control additives) is present in the wellbore fluid. Nevertheless, in certain cases, solid additives can be added to the wellbore fluid for specific purposes.)

Aqueous base completion fluids can cause swelling of clay-containing structures in a pay zone. For example, reservoir rocks containing volcanic ash and/or smectic or mixed layer clays could be permanently damaged if contacted with an aqueous base fluid. In addition, brine-in-oil emulsions can also cause clay swelling due to the internal water phase of the emulsion. Furthermore, the emulsifiers present in brine-in-oil emulsions can cause detrimental formation wettability changes.

Clean hydrocarbon oils (e.g., crude oil) are the least damaging completion fluids to be placed across an oil-bearing formation. See, for example, European Patent Application No. 87304548.8 and SPE 17161. Until recently, there was no oil-soluble material available to increase the density of the oil. See SPE 17161. However, European Patent Application No. 87304548.8 discloses that halogenated organic compounds (e.g., brominated aromatic ethers, diphenyls, aliphatic hydrocarbons, benzene, and alkyl benzenes) can be dissolved in an organic solvent such as crude oil, kerosene, diesel oil or a low toxicity drilling oil. Unfortunately, these halogenated hydrocarbons have several drawbacks. For example, they tend to be very costly, can be environmentally hazardous, and may cause adverse effects on downstream processing equipment (e.g., catalyst poisoning).

It would be desirable to have solids-free, non-aqueous completion or wellbore fluids that do not possess the disadvantages of the halogenated organic compounds of European Patent Application No. 87304548.8. Furthermore, it would be advantageous to have a method for further increasing the density of the halogenated organic compounds disclosed in European Patent Application No. 87304548.8 to reduce the amount of such halogenated organic compounds (e.g., by further dilution with a hydrocarbon diluent) required in a well completion or workover procedure. In addition, it would be beneficial to improve the performance of brine-in-oil or invert emulsions by (a) increasing the stability of such emulsions and/or (b) reducing their emulsion concentration to diminish or alleviate formation wettability changes.

The present invention provides (A) high density, solids-free wellbore fluids, (B) methods for improving the quality of the solids-free wellbore fluids, (C) invert emulsion wellbore fluids having reduced emulsion concentrations and/or improved stability, (D) drilling, well completion, and workover methods employing such wellbore fluids, and (E) natural resource systems containing these fluids. In one embodiment of the present invention, the solids-free wellbore fluid comprises an aromatic solvent having a density at about 15.6.degree. C. (60.degree. F.) of at least about 0.9 g/ml (7.5 pounds per gallon (ppg)), a flash point of greater than about 54.4.degree. C. (130.degree. F.), a solubility in water at about 25.degree. C. (77.degree. F.) of less than about 1 weight percent, a solubility in benzene at about 25.degree. C. (77.degree. F.) of at least about 80 weight percent, a viscosity at about 37.8.degree. C. (100.degree. F.) of less than about 0.2 newton second/meter.sup.2 (200 cps), and a pour point of less than about 15.6.degree. C. (60.degree. F.).

At present there are few sources for such aromatic solvents and a significant percent of the aromatic solvents are unsatisfactory due to contaminants which decrease the permeability of oil producing subterranean formations. Accordingly, the present invention also provides techniques for remediating aromatic solvents. In one remediation technique, particulates greater than a predetermined size (e.g., larger than about 10 micron) are separated from the aromatic solvent. In another remediation procedure, solid paraffins present in the aromatic solvent are dissolved by (a) adding up to about 10 weight percent of an aliphatic-containing solvent to the aromatic solvent (the weight percent being based upon the weight of the aromatic solvent) to form an intermediate oil; (b) heating the intermediate oil to dissolve the paraffins and form a heated solution; and (c) cooling the heated solution to form a modified paraffin-containing aromatic solvent that is a solution at 25.degree. C. (77.degree. F.).

In another version of the invention, the wellbore fluid comprises an organic fluid. (As used in the specification and claims, the term "organic fluid" means a carbon-containing compound having (i) a melting point less than about 20.degree. C. (about 68.degree. F.), (ii) a flash point greater than about 54.4.degree. C. (about 130.degree. F.), and (iii) a dipole moment greater than 0 debye (D).) The organic fluid comprises one or more halogenated compounds (such as those described in European Patent Application No. 87304548.8) and/or one or more unhalogenated compounds. When a low density organic fluid is employed (e.g., an organic fluid having a density of less than about 1 g/ml (8.35 pounds per gallon (ppg)), a salt is generally dissolved in the organic fluid to increase the density of the organic fluid while enabling the organic fluid to remain solids-free. When a high density organic fluid is used (e.g., an organic fluid having a density of at least about 1 g/ml (8.35 ppg)), the organic fluid is commonly dissolved in a hydrocarbon diluent (e.g., the aromatic solvent) to increase the density of the hydrocarbon diluent.

While a solids-free, all-oil wellbore fluid is preferred for use in completing or otherwise treating a well or subterranean formation, the fact of the matter is that such fluids appear to have a maximum density of about 1.44 g/ml (12 ppg). Hence, since a significant number of completion and well workover fluids are required to have a density greater than about 1.44 g/ml (12 ppg), the present invention also provides a stabilized invert emulsion wellbore fluid having a density up to about 2 g/ml (16.8 ppg). The invert emulsion wellbore fluid comprises an oil, a brine, and an emulsifier and is characterized in that the oil has a specific gravity of at least 1 and/or the brine density (x) is related to the emulsion density (y) by the formula y.gtoreq.(.times.+4.5)/1.67 and/or the oil has an aromatic content of at least about 70 weight percent, the weight percent being based on the entire weight of the oil.

Optionally, the wellbore fluids of the present invention further comprise the hydrocarbon diluent (e.g., crude oil, kerosene, diesel oil, polyalphaolefins (such as those described in U.S. Pat. No. 5,096,883, which patent is incorporated herein in its entirety by reference), mineral oil, gasoline, naphtha, aromatic solvents, and mixtures thereof) and/or an additive (e.g., acids, bases, buffers, viscosifiers, corrosion inhibitors, antioxidants, proppants for use in hydraulically fracturing subterranean formations, particulate agents for use in forming a gravel pack, organophilic clays, fluid loss control agents, mutual solvents, water-wetting surfactants, and mixtures thereof).

The wellbore fluids of the present invention can be employed in virtually any well drilling or completion or workover operation (e.g., pay zone drilling, underreaming, drilling in, plugging back, sand control, perforating, gravel packing, chemical treatment, hydraulic fracturing, cleanout, well killing, tubing and hardware replacement, and zone selective operations). In addition, the wellbore fluids can be used as a packer fluid.

Regarding the natural resource system of the present invention, such system comprises a subterranean formation (generally containing a natural resource such as crude oil, natural gas, and/or a geothermal fluid), a well penetrating at least a portion of the subterranean formation, and the solids-free or invert emulsion wellbore fluid present, for example, in at least a portion of the well and/or the subterranean formation.

The organic fluid employed in the present invention preferably has a melting point less than about 16.degree. C. (about 60.degree. F.), more preferably less than about 10.degree. C. (about 50.degree. F.), even more preferably less than about 5.degree. C. (about 41.degree. F.), and most preferably less than about 0.degree. C. (about 32.degree. F.). The flash point of the organic fluid is preferably greater than about 60.degree. C. (about 140.degree. F.), more preferably greater than about 65.6.degree. C. (about 150.degree. F.), and most preferably greater than about 71.1.degree. C. (about 160.degree. F.). In the embodiments of the invention where a salt is dissolved in the organic fluid, the dipole moment of the organic fluid is preferably greater than about 0.5, more preferably greater than about 1, and most preferably greater than about 1.5 D. In general, when all other factors (e.g., cost, toxicity, and melting and flash points) are the same and when a salt is dissolved in the organic solvent, it is preferred to employ the organic fluid having the highest dipole moment. When a salt is not dissolved in the organic fluid, the organic solvent need not have a high dipole moment and commonly has a density of at least about 1 g/ml (8.35 ppg), preferably at least about 1.05 g/ml (8.77 ppg), more preferably at least about 1.1 g/ml (9.19 ppg), even more preferably at least about 1.15 g/ml (9.60 ppg), and most preferably at least about 1.2 g/ml (10.02 ppg).

Generally, the organic fluid employed in the present invention has a solubility in 100 g of water at 25.degree. C. (77.degree. F.) of less than about 10, preferably less than about 5, more preferably less than about 1, and most preferably less than about 0.1 g. In fact, it is even desirable for the organic fluid to be substantially insoluble and even more desirable for the organic fluid to be virtually insoluble in 100 g water at 25.degree. C. (77.degree. F.). (As used in the specification and claims, the term "substantially insoluble" when used in conjunction with the solubility of the organic fluid in water means that less than about 0.01 g of the organic fluid is soluble in 100 g water at 25.degree. C. (77.degree. F.); and the term "virtually insoluble" when used in conjunction with the solubility of the organic fluid in water means that less than about 0.001 g of the organic fluid is soluble in 100 g water at 25.degree. C. (77.degree. F.).)

Exemplary classes of organic fluids for use in the present invention include, but are not limited to, aryl halides (usually containing about 6 to about 7 carbon atoms), heterocyclic compounds (generally containing about 5 to about 9 carbon atoms), alkyl halides (typically containing about 6 to about 8 carbon atoms), carboxylic acids (commonly containing about 4 to about 18 carbon atoms), amines (often containing about 6 to about 16 carbon atoms), esters (frequently containing about 6 to about 16 carbon atoms), alcohols (ordinarily containing about 6 to about 16 carbon atoms), aldehydes (commonly containing about 7 to about 8 carbon atoms), ketones (generally containing about 6 to about 12 carbon atoms), ethers (usually containing about 8 to about 14 carbon atoms), plant oils, and animal oils. The organic fluids are employed in the invention individually or in any combination thereof. Representative organic fluids are set forth in the following Table I:

The preferred organic fluids are esters and alcohols.

The salts dissolved in the organic fluid are generally inorganic salts. Exemplary inorganic salts include, but are not limited to, zinc halides, alkaline earth metal halides, cadmium halides, alkali halides, tin halides, arsenic halides, copper halides, aluminum halides, silver nitrate, mercury halides, mercuric cyanide, lead nitrate, copper sulfate, nickel halides, cobalt halides, manganese halides, and chromium halides. The preferred halides are chlorine, bromine, and iodine; the preferred alkali metals are lithium, sodium, potassium, rubidium, and cesium; and the preferred alkaline earth metals are magnesium, calcium, strontium, and barium. An individual salt as well as combinations of two or more salts are used in the wellbore fluid.

The concentration of the salt in the organic fluid depends on the desired density of the wellbore fluid. In general, any concentration of salt up to the solubility limit of the salt in the organic fluid can be used. Typically, the wellbore fluid contains at least about 0.1, preferably at least about 1, more preferably at least about 10, even more preferably at least about 25, and most preferably at least about 50, weight percent dissolved salt. (As used in the specification and claims, the term "weight percent" when used to designate the concentration of the dissolved salt in the wellbore fluid means the weight of the dissolved salt in the wellbore fluid divided by the sum of the weights of the organic fluid and dissolved salt in the wellbore fluid, the quotient being multiplied by 100 percent.) Quite often, the solubility limit of the salt in the wellbore fluid is less than about 75 weight percent, more typically less than about 50 weight percent, and usually less than about 25 weight percent.

In another embodiment of the present invention, the wellbore fluid comprises an aromatic solvent. In this version of the invention, the aromatic solvent generally has a density at about 15.6.degree. C. (60.degree. F.) of at least about 0.9 g/ml (7.5 ppg), preferably at least about 0.925 g/ml (7.72 ppg), more preferably at least about 0.95 g/ml (7.93 ppg), even more preferably at least about 0.975 g/ml (8.14 ppg), and most preferably at least about 1 g/ml (8.35 ppg). Typically, the aromatic solvent has a flash point greater than about 54.4.degree. F. (about 130.degree. F.), preferably greater than about 60.degree. C. (about 140.degree. F.), more preferably greater than about 65.6.degree. C. (about 150.degree. F.), and most preferably greater than about 71.1.degree. C. (about 160.degree. F.). The pour point of the aromatic solvent is usually less than about 15.6.degree. C. (60.degree. F.), preferably less than about 4.4.degree. C. (40.degree. F.), and more preferably less than about -6.7.degree. C. (20.degree. F.). Commonly, the aromatic solvent has a viscosity of less than about 0.2 newton second/meter.sup.2 (N-sec/m.sup.2) (200 cps), with the viscosity being preferably less than about 0.15 N-sec/m2 (150 cps), more preferably less than about 0.1 N-sec/m2 (100 cps), even more preferably less than about 0.05 N-sec/m2 (50 cps), and most preferably less than about 0.025 N-sec/m.sup.2 (25 cps).

Regarding the solubility of the aromatic solvent in water and benzene, the solubility of the aromatic solvent in water at 25.degree. C. (77.degree. F.) is generally less than about 1, preferably less than about 0.5, more preferably less than about 0.25, and most preferably less than about 0.1 weight percent. In fact, it is even desirable for the aromatic solvent to be substantially insoluble and even more desirable for the organic fluid to be virtually insoluble in 100 g water at 25.degree. C. (77.degree. F.). (As used in the specification and claims, the term "substantially insoluble" when used in conjunction with the solubility of the aromatic solvent in water means that the solubility of the aromatic solvent in water at 25.degree. C. (77.degree. F.) is less than about 0.01 weight percent; and the term "virtually insoluble" when used in conjunction with the solubility of the aromatic solvent in water means that the solubility of the aromatic solvent in water at 25.degree. C. (77.degree. F.) is less than about 0.001 weight percent.)

In benzene at 25.degree. C. (77.degree. F.), the aromatic solvent has a solubility of generally at least about 80, preferably at least about 85, more preferably at least about 90, even more preferably at least about 95, and most preferably at least about 99 weight percent. In fact, it is preferred that the aromatic solvent be completely miscible in benzene at 25.degree. C. (77.degree. F.).

Exemplary aromatic solvents meeting the above requirements are set forth in Mellan, Handbook of Solvents, Volume 1, Reinhold Publishing Corporation, New York, N.Y. (1957) and Mardsen, Solvents Guide, Second Edition, Interscience Publishers, A Division of John Wiley and Sons, Inc., New York, N.Y. (1963), both of these publications being incorporated in their entireties by reference. Preferred aromatic solvents include those listed in the following Table II:

Many of the commercially available aromatic solvents contain contaminants that reduce the permeability of or otherwise adversely affect the production of oil from subterranean formations. For example, some aromatic solvents (e.g., oils (such as light cycle, heavy cycle, and decant oils) obtained from fluid catalytic cracker and resid catalytic cracker units) contain catalyst fines, oxidation products, and/or asphaltenes which are believed to plug or otherwise damage a subterranean formation. These particles are separated from the aromatic solvent by passing the solvent through a sieve having a mesh size typically equal to or less than the maximum pore size of the subterranean formation where the aromatic solvent is to be used. To further reduce the risk of damaging the subterranean formation, even finer mesh size sieves can be used (e.g., mesh sizes equal to or less than the average, lower quartile, or lower 10 percent pore size of the subterranean formation). In numerical terms, the sieve generally has a pore size less than about 10, preferably less than about 5, more preferably less than about 2, even more preferably less than about 1, and most preferably less than about 0.5, microns.

When a sufficient concentration of paraffins is present in the particulate-containing aromatic solvent to cause the aromatic solvent to appear cloudy at room temperature, the paraffins inhibit the filtration of the solvent at room temperature. Accordingly, prior to filtering a cloudy paraffin-containing aromatic solvent, the paraffins are dissolved by adding an organic liquid to the aromatic solvent and heating the resulting composition. (As used in the specification and claims, the term "organic liquid" means a carbon-containing material that is a liquid at 20.degree. C.) The organic liquid usually has a specific gravity of less than 1 at 20/4.degree. C. Typical organic liquids include, but are not limited to, diesel (specific gravity of less than 1 at 20/4.degree. C.), kerosene (specific gravity of about 0.81 at 20/4.degree. C.), and mineral oil.

An adequate amount of organic liquid is added to the aromatic solvent to dissolve the paraffins present in the solvent when the organic liquid-aromatic solvent combination is heated. However, the concentration of the organic liquid in the aromatic solvent should be small enough so that the density of the final combination is not significantly less than the density of the aromatic solvent. Hence, the amount of organic liquid employed is typically about 1 to about 10, more commonly about 2 to about 7, weight percent, the weight percent being calculated by dividing the weight of the organic liquid by the weight of the aromatic solvent and multiplying the quotient by 100 percent.

The resulting organic liquid-aromatic solvent combination is then heated to a temperature sufficient to solubilize the paraffins therein, thereby forming a solution. Generally, the temperature of the combination is raised to about 37.8.degree. C. (100.degree. F.), preferably about 40.6.degree. C. (105.degree. F.), and most preferably about 43.3.degree. C. (110.degree. F.).

Next, the solution is allowed to cool to ambient temperature. At ambient temperature the solution surprisingly remains homogenous.

An alternative method for separating the particulates from aromatic solvents takes advantage of the heavier density of the particulate matter. More specifically, since the particulates tend to be denser than the aromatic solvent, most of the particulate matter can be separated from the aromatic solvent by siphoning or otherwise removing the solvent from a vessel (e.g., a storage tank) while leaving the particulate matter at the bottom of the vessel.

While all-oil wellbore fluids are preferred, some applications require a fluid density not achievable by all-oil well bore fluids, e.g., densities greater than about 1.44 g/ml (12 ppg). For such instances, the present invention provides a stabilized invert emulsion wellbore fluid of the type comprising an oil, a brine, and an emulsifier. The invert emulsion of the present invention can employ the same types of brines and emulsifiers used in current invert emulsions. See, for example, U.S. Pat. No. 4,381,241 and SPE 17161, which documents are incorporated herein in their entireties by reference. In addition, the concentration of oil, brine, and emulsifiers utilized in the invert emulsion of the present invention is also analogous to those used in prior invert emulsion formulations. See, for example, U.S. Pat. No. 4,381,241 and SPE 17161.

The improved stability of the present invert emulsions is achieved by selecting the oil from the above described organic fluids and aromatic solvents which have a specific gravity greater than 1. The reason for selecting dense oils is because, when all other parameters are held constant, the stability of the emulsion improves as the density of the oil approaches the density of the brine. Another advantage of using a dense oil is that, for a given invert emulsion density, lower concentrations of expensive salt (i.e., brine) are required to weight up the internal aqueous phase and lower amounts of expensive emulsifiers are required to stabilize the emulsion. This feature of the invert emulsions of the present invention can be graphically depicted. In particular, FIG. 1 of SPE 17161 plots the relationship between emulsion density (y) and brine density (x). The upper limit of the optimum range of brine density for use in producing a specific emulsion density is described by the equation y=(.times.+4.5)/1.67. Accordingly, since a given emulsion density can be achieved in the present invention with a less dense brine due to the use of a denser oil phase, the invert emulsions of the present invention extend the optimum upper limit of the emulsion density-brine density relationship so that invert emulsions described by the equation y.gtoreq.(.times.+z)/1.67, wherein z is a number equal to or greater than 4.5 (e.g., 4.6, 4.7, 4.8, or more), also fall with the extended optimum range.

Alternatively, for a given emulsifier and brine concentration, a higher invert emulsion density can be achieved using a high density organic fluid and/or aromatic solvent. In addition, the high aromatic and/or cyclic content of dense organic fluids and aromatic solvents further stabilizes the emulsion due to the polarity of such compounds. For example, the dense organic fluids and aromatic solvents employed in the invert emulsions typically have an aromatic content well over about 70 (e.g., 80, 90, 95 and more) weight percent.

The all-oil and invert emulsion wellbore fluids of the present invention optionally contain one or more additional ingredients such as hydrocarbon diluents, proppants suitable for use in hydraulically fracturing subterranean formations, particulate agents suitable for use in forming a gravel pack, corrosion inhibitors, acids, bases, buffers, viscosifiers, antioxidants, organophilic clays, fluid loss control agents, mutual solvents, and water-wetting surfactants. Typical hydrocarbon diluents include, but are not limited to, crude oil, kerosene, diesel oil, polyalphaolefins, mineral oil, gasoline, naphtha, and aromatic solvents. In a preferred embodiment of the present invention, a high density organic fluid (e.g., an ester such as a dialkyl phthalate having 1 to about 4 carbon atoms) is dissolved in the hydrocarbon diluent.

The concentration of the hydrocarbon diluent in the wellbore fluid depends on the desired density of the wellbore fluid. Since the hydrocarbon diluent usually costs less than the organic fluid, it is usually desirable to use as much hydrocarbon diluent in the wellbore fluid as possible while achieving the desired density of the wellbore fluid. Generally, the hydrocarbon diluent is present in the wellbore fluid in a concentration of at least about 5, preferably at least about 10, more preferably at least about 25, even more preferably at least about 50 weight percent, and most preferably at least about 70 weight percent. (As used in the specification and claims, the term "weight percent" when used to designate the concentration of the hydrocarbon diluent in the wellbore fluid means the weight of hydrocarbon diluent in the wellbore fluid divided by the sum of the weights of the organic fluid, the dissolved salt, and the hydrocarbon diluent in the wellbore fluid, the quotient being multiplied by 100 percent.) While higher hydrocarbon diluent concentrations can be employed in the wellbore fluid, the wellbore fluid usually contains about 95 weight percent or less, commonly about 90 weight percent or less, more commonly about 85 weight percent or less, even more commonly about 80 weight percent or less, and most typically about 75 weight percent or less, hydrocarbon diluent.

When the hydrocarbon diluent is employed in conjunction with an organic fluid containing a dissolved salt, the dissolved salt-containing organic fluid is preferably miscible in the hydrocarbon diluent in at least the amount added to the hydrocarbon diluent. More preferably, the dissolved salt-containing organic fluid is miscible in the hydrocarbon diluent in all concentrations.

Common proppants suitable for use in hydraulic fracturing procedures are quartz sand grains, tempered glass beads, sintered bauxite, resin coated sand, aluminum pellets, and nylon pellets. Generally, the proppants are employed in the wellbore fluids of the present invention intended for use as hydraulic fracturing fluids and are used in concentrations of roughly about 1 to about 10 pounds per gallon of the wellbore fluid. The proppant size is typically smaller than about 2 mesh on the U.S. Sieve Series scale, with the exact size selected being dependent on the particular type of formation to be fractured, the available pressure and pumping rates, as well as other factors known to those skilled in the art.

Typical particulate agents employed in the wellbore fluids of the present invention used as gravel packing fluids include, but are not limited to, quartz sand grains, glass beads, synthetic resins, resin coated sand, walnut shells, and nylon pellets. The gravel pack particulate agents are generally used in concentrations of about 1 to about 20 pounds per gallon of the wellbore fluid. The size of the particulate agent employed depends on the type of subterranean formation, the average size of formation particles, and other parameters known to those skilled in the art. Generally, particulate agents of about 8 to about 70 mesh on the U.S. Sieve Series scale are used.

Some of the organic fluids (e.g., aniline) which can be employed in the present invention also function as corrosion inhibitors. When such dual acting organic fluids are used in the present invention, there is generally no need for an additional corrosion inhibitor. When such dual acting organic fluids are not employed in formulating the wellbore fluid or when an additional corrosion inhibitor is desired, the corrosion inhibitor selected can be an inorganic and/or organic compound.

Inorganic corrosion inhibitors include, but are not limited to, chromates (e.g., sodium chromate), phosphates (e.g., sodium phosphate), nitrites, silicates, borates, and arsenic. When used, the inorganic corrosion inhibitors are preferably present in the wellbore fluid in a concentration of at least about 0.0001, more preferably at least about 0.0005, and most preferably at least about 0.001, moles per liter of the wellbore fluid. The maximum concentration of the inorganic corrosion inhibitors in the wellbore fluid is generally less than about 0.1, preferably less than about 0.05, and more preferably less than about 0.01, moles per liter of the wellbore fluid.

Exemplary organic compounds capable of functioning as a corrosion inhibitor in the wellbore fluid of the present invention include, but are not limited to, pyridine, butylamine, benzoic acid, benzosulfonic acid, nonamethyleneamine, diphenyl urea, carbon disulfide, allylthiourea, octyldecylamine, and hexadecylamine. When employed in the wellbore fluid, the organic corrosion inhibitors are preferably present in a concentration of at least about 0.1, more preferably at least about 0.5, and most preferably at least about 1, weight percent based on the entire weight of the wellbore fluid. Typically, the maximum concentration of the organic corrosion inhibitor in the wellbore fluid is less than about 10, preferably less than about 5, and most preferably less than about 2.5, weight percent based on the entire weight of the wellbore fluid.

Acids, bases, and buffers are employed in the wellbore fluid to help maintain the dissolved salts in solution when the wellbore fluid is contacted by subterranean materials (e.g., water) having a pH capable of causing the precipitation of the dissolved salts. Some of the organic fluids employed in the present invention are acids (e.g., carboxylic acids) or bases (e.g., aniline, octylamine, quinoline) and, when used, generally negate the need for any additional acid or base, respectively. When acidic organic fluids are not used or when it is desired to use an additional acidic component in the wellbore fluid, the acid selected can be one or more inorganic and/or organic compounds. Common inorganic acids are hydrochloric acid, hydrobromic acid, hydrofluoric acid, nitric acid, phosphoric acid, orthophosphoric acid, sulfurous acid, sulfuric acid, boric acid, carbonic acid, chromic acid, hydroiodic acid, percholic acid, and alumic acid. Typical organic acids include oxalic acid, formic acid, caprylic acid, oleic acid, ascorbic acid, benzoic acid, butyric acid, lactic acid, acetic acid, and citric acid.

When basic organic fluids are not used or when it is desired to use an additional basic component in the wellbore fluid, the base selected can be one or more inorganic and/or organic compounds. Illustrative inorganic bases are hydroxides (e.g., ammonium, alkali, and alkaline earth metal hydroxides), bicarbonates (e.g., alkali bicarbonate), carbonates (e.g., alkali carbonates), lime, and ammonia. Exemplary organic bases are acetamide, ethylenediamine, hydrazine, pyridine, benzylamine, butylamine, thiazole, toluidine, and urea.

The buffering agents employed in the present invention generally have a buffering capacity in a least a portion of the pH range of about 6 to about 8, preferably about 6.5 to about 7.5, and most preferably about 6.8 to about 7.2. Buffer agents having a buffering capacity in at least a portion of the above pH ranges are set forth in Lange's Handbook of Chemistry, Editor: John A. Dean, 12th Edition, McGraw-Hill Book Co., New York, N.Y. (1979), pages 5-73 to 5-84, this publication being incorporated herein in its entirety by reference. More specifically, phosphates (e.g., potassium dihydrogen phosphate, disodium monohydrogen phosphate), phosphate-hydroxide combinations (e.g., potassium dihydrogen phosphate and sodium hydroxide), phosphate combinations (e.g., potassium dihydrogen phosphate and disodium monohydrogen phosphate), 2-(N-morpholino)ethanesulfonic acid-sodium hydroxide combinations, 2,2-bis(hydroxymethyl)-2,2',2"-nitriloethanol-hydrochloric acid combinations, potassium dihydrogen phosphate-borax combinations, N-tris(hydroxymethyl)methyl-2-aminoethanesulfonic acid-sodium hydroxide combinations, triethanolamine-hydrochloric acid combinations, and diethylbarbiturate-hydrochloric acid combinations are some of the buffering agents having a buffering capacity within at least a portion of the aforementioned pH ranges.

The concentration of acid, base, or buffer employed in the wellbore fluid is dependent upon the subterranean conditions that the wellbore fluid is expected to encounter (e.g., the amount and pH of subterranean water expected to be in contact with the wellbore fluid). In general, when employed, the acid, base, or buffer is used in a concentration of at least about 0.01, preferably at least about 0.05, and more preferably at least about 0.1 weight percent based on the entire weight of the wellbore fluid. Typically, the maximum concentration of the acid, base, or buffer in the wellbore fluid is less than about 10, preferably less than about 5, and more preferably less than about 1 weight percent based on the entire weight of the wellbore fluid.

Exemplary antioxidants employed in the present invention are 2,6-ditertbutyl-p-cresol, butylated-hydroxy-anisole (BHA), butylated-hydroxy-toluene (BHT), tert-butyl-hydroquinone (TBHQ), o-cyclohexylphenol, and p-phenylphenol. When used, the antioxidants are generally present in the wellbore fluid in a concentration of at least about 0.0015, preferably at least about 0.01, and more preferably at least about 0.1, but typically less than about 10, preferably less than about 5, and more preferably less than about 1, weight percent based on the entire weight of the wellbore fluid.

Illustrative viscosifiers, organophilic clays, and fluid loss control (FLC) agents optionally used in the present invention as well as their general and preferred concentrations in the wellbore fluid are set forth in the following Table III.

Exemplary mutual solvent solvents include, but are not limited to, glycols (e.g., ethylene glycol monobutyl ether, 1,2-propylene glycol, ethylene glycol, and diethylene glycol dimethyl ether) and alcohols (e.g., octanol, cyclohexanol, and 1-decanol). When employed in the wellbore fluids of the present invention, the mutual solvents are typically present in a concentration of about 5 to about 10 weight percent, based upon the entire weight of the wellbore fluid.

Water-wetting surfactants include, but are not limited to, fluorinated surfactants such as perfluoroalkyl sulfonates, perfluorocarboxylic acids, and polylfluoroakane phosphonates. When used, these surfactants are generally present in small concentrations (e.g., less than 5 and more typically about 0.1 to about 2, weight percent based on the entire weight of the wellbore fluid).

The salt-containing wellbore fluid of the present invention is prepared by dissolving the salt in the organic fluid, preferably with vigorous stirring. Generally, the salt is added slowly or incrementally to the organic fluid to allow the added salt to dissolve prior to adding any significant amount of additional salt. While heat can be employed to increase the dissolution rate of the salt in the organic fluid, it is preferred to not use heat in order to avoid potential detrimental chemical reactions and/or thermal degradation of the organic fluid. In addition, acids, bases, buffering agents, and antioxidants are typically added to the organic fluid either before, during, or after the addition of the salt.

When a hydrocarbon diluent is employed in a wellbore fluid comprising an organic fluid and a dissolved salt, the dissolved salt-containing organic fluid and hydrocarbon diluent are combined and any additional additive (e.g., hydraulic fracturing proppants, gravel pack particulate agents, viscosifiers, corrosion inhibitors, fluid loss control agents, and organophilic clays) is usually added to resulting combination. In those instances where a hydrocarbon diluent is not used, the additional additives are preferably added to the dissolved salt-containing organic fluid.

When a salt is not used as a weighting agent, the organic fluid and hydrocarbon diluent are combined and any additional additive (e.g., hydraulic fracturing proppants, gravel pack particulate agents, viscosifiers, corrosion inhibitors, fluid loss control agents, and organophilic clays) is usually added to resulting combination. In those instances where a hydrocarbon diluent is not used, the additional additives are preferably added to the organic fluid. In addition, when an aromatic solvent is employed as the wellbore fluid, any additional additives are typically added to the aromatic solvent.

The resulting wellbore fluid is preferably stored under conditions which prevent photochemical reactions (e.g., stored in dark glass or metal containers) and oxidation (stored in containers with little, if any, air space).

The specific techniques used when employing the wellbore fluid of this invention are determined by its intended use and are analogous to methodologies employed when using prior art wellbore fluids for corresponding well drilling or completion or workover operations. For example, when the wellbore fluid is employed as a gravel packing fluid, it is typically injected into the formation in accordance with the procedure discussed in U.S. Pat. No. 4,552,215, this patent being incorporated herein in its entirety by reference.

When employed as a fracturing fluid, the wellbore fluid of the present invention is usually injected into the formation using procedures analogous to those disclosed in U.S. Pat. No. 4,488,975, U.S. Pat. No. 4,553,601, Howard et al., Hydraulic Fracturing, Society of Petroleum Engineers of the American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc., New York, N.Y. (1970), and Allen et al., Production Operations, Well completions, Workover and Stimulation, 3rd Edition, volume 2, Oil & Gas Consultants International, Inc., Tulsa, Okla. (1989) (Allen), chapter 8, these publications being incorporated herein in their entirety by reference.

When employed in a perforating operation, the wellbore fluid of the present invention is used according to the methodologies disclosed in chapter 7 of Allen, this publication having been incorporated herein in its entirety by reference.

Techniques for using packer fluids and well killing fluids, such as those discussed in chapter 8 of Allen, are also applicable to the wellbore fluid of the present invention.

The following examples are intended to illustrate, and not limit, the invention. Examples 1-27 demonstrate the dissolution of several salts in a variety of esters and Example 28 details the formation of a three-component wellbore fluid comprising (a) an organic fluid, (b) a dissolved salt, and (c) a hydrocarbon diluent. Example 29 sets forth the methodology employed in preparing a two-component system comprising (a) an organic fluid and (b) a hydrocarbon diluent. Core flow tests are detailed in Examples 30 (using the two-component system prepared in Example 29) and 31 (employing a single-component system, namely, an aromatic solvent). Examples 32-34 compare three techniques for dissolving paraffins in heavy cycle oil and Examples 35-38 document the improved return permeability achieved by filtering various oils. A typical oil-phase cleanup fluid formulation is given in Example 39.

A salt (either CaBr.sub.2, ZnBr.sub.2, or ZnCl.sub.2) was dissolved in each of nine different ester samples to determine the approximate solubility limits and the viscosities of the resulting fluids. Each salt was weighed out in about 0.5 g increments and then placed in a 50 ml beaker containing about 5 g of one of the esters. The samples were heated on a hot plate to about 65.6.degree. C. (about 150.degree. F.) to speed up the dissolution of the respective salt. Observations (e.g., rate of dissolution and sample color and texture) were recorded. The resulting fluids were cooled to room temperature and the viscosity of each such fluid was determined at about 24.4.degree. C. (about 76.degree. F.) in a capillary viscometer. Visual observation of the rate of dissolution was used to roughly determine whether a saturated solution was obtained. The results of this experiment are shown below in Table A.

The data shown in Table A indicates that various salts can be dissolved in organic fluids to form a wellbore fluid having a higher density than the respective constituent organic fluids.

At ambient room temperature (about 20.1.degree. C. (about 70.degree. F.)), anhydrous zinc bromide (about 100 g) was added to about 100 g n-octanol in about 20 g increments while stirring the sample vigorously with a stirring bar. After the zinc bromide was completely dissolved, about 250 g of No. 2 diesel diluent were added to the zinc bromide-containing n-octanol using gentle mixing. The resulting wellbore fluid (about 450 g) had a density of about 8.5 pounds per gallon.

The above Example 28 demonstrates that salts can be dissolved in an organic fluid and the resulting combination diluted with a hydrocarbon diluent.

At ambient room temperature (about 21.1.degree. C. (70.degree. F.)), diethyl phthalate (about 315 g) was added to kerosene (about 185 g) gradually in about 30 g increments while vigorously stirring the sample with a stirring bar. The resulting wellbore fluid (about 500 g) had a density of about 1.018 g/ml (8.5 ppg).

Core Sample:

The core sample employed in this experiment was a water-sensitive West Foreland core having the following approximate characteristics:

Test Protocol:

Kerosene (87 pore volumes) were flowed through the core at ambient conditions using a pressure differential of about 30 psi. The flow rate was allowed to line out. After the flow rate lined out, the two-component system prepared in Example 29 (about 32 pore volumes) was flowed through the core using a pressure differential of about 30 psi. The flow rate was again allowed to line out. Finally, kerosene was again flowed through the core using a pressure differential of about 30 psi and the flow rate was also allowed to line out to obtain the return permeability.

Test Results:

The kerosene flow rate prior to passing the two-component system through the core was about 3.7 cc/min and after passing the two-component system through the core was about 3.5 cc/min. Hence, the return permeability was about 95%.

Core Sample:

Same as employed in Example 30.

Test Protocol:

Kerosene (121 pore volumes) was flowed through the core at ambient conditions using a pressure differential of about 30 psi. PANASOL AN-3S brand aromatic solvent (about 82 pore volumes) was flowed through the core using a pressure differential of about 30 psi. Finally, kerosene (about 47 pore volumes) was again flowed through the core using a pressure differential of about 30 psi to obtain the return permeability.

Test Results:

The kerosene flow rate prior to passing the PANASOL AN-3S brand aromatic solvent through the core was about 5.1 cc/min and after passing the PANASOL AN-3S brand aromatic solvent through the core was about 5.0 cc/min. Hence, the return permeability was about 98%.

A heavy cycle oil having a cloudy, brownish-yellow appearance at about 21.1.degree. C. (70.degree. F.) and the properties shown in the following Table B was employed in Examples 32-34.

When the above-described oil was filtered using a 0.5 micron filter, the filter partially plugged from the paraffins. This paraffin filter cake could be washed away using kerosene.

In the first experiment, the heavy cycle oil was heated to about 48.9.degree. C. (120.degree. F.), which dissolved the paraffins (as noted by a clearing of the oil to give a transparent, brownish-yellow color). However, when the oil cooled down to about 21.1.degree. C. (70.degree. F.), the cloudy appearance returned.

In another experiment, kerosene (about 5 weight percent based upon the weight of the heavy cycle oil) was added to the heavy cycle oil. The cloudy appearance remained, indicating that the paraffins had not dissolved.

In a third experiment, kerosene (about 5 weight percent based upon the weight of the heavy cycle oil) was added to the heavy cycle oil and the resulting mixture was then heated to about 43.3.degree. C. (110.degree. F.). At this point, the paraffins dissolved as indicated by the transparent brownish-yellow color. After the mixture had cooled down to room temperature, the oil was still transparent--indicating that the paraffins were still dissolved in the oil. The cooled, transparent, brownish-yellow oil was passed through a 0.5 micron filter without plugging the filter. Subsequently, a formation damage test conducted using West Foreland core with kerosene as the simulated formation oil. A return permeability of about 95 percent was obtained, which showed virtually no productivity damage due to the conditioned heavy cycle oil.

Laboratory coreflow tests were conducted to investigate whether filtration could improve the return permeability achieved with all-oil completion fluids. These tests were performed at ambient temperature using water-sensitive West Foreland cores having an air permeability of about 100 md and a porosity of about 20 percent and composed of medium grain sand and 2 to 3 percent pore lining smectite. The results of the tests are summarized in Table C below.

The coreflow test data reported in the above Table C showes that formation damaging solids can be filtered out with a 0.5 micron filter regardless of whether they are catalyst fines from an oil refinery or oxidation products.

A typical oil-phase fluid cleanup fluid comprises about 90 weight percent of a high density oil (e.g., light or heavy cycle oil), about 9 weight percent of a mutual solvent (e.g., ethylene glycol monobutyl ether), and about 1 weight percent of a water-wetting surfactant (e.g., perfluoroalkyl sulfonate). Operational hazards associated with diesel/mutual solvent treatments are substantially reduced, if not completely eliminated, due to the presence of a high density oil in the oil-phase cleanup fluid of the present invention. For example, the higher density of the oils employed in the present invention makes handling less hazardous due to surface pressures required during remedial treatments such as those for rectifying drilling mud-related productivity damage. In addition, the flash points of dense oils are significantly higher than the flash point of diesel, thereby reducing the flammability hazard. Furthermore, the high aromatic content of dense oils makes them better solvents than diesel for asphaltenes and other oil-based mud additives.

Although the present invention has been described in detail with reference to some preferred versions, other versions are possible. For example, in another version of the invention, the organic fluid is employed as the wellbore fluid in well drilling or completion or workover operations, with or without one or more of the optional additives (e.g., hydrocarbon diluents, hydraulic fracturing proppants, gravel pack particulate agents, corrosion inhibitors, acids, bases, buffers, viscosifiers, antioxidants, organophilic clays, land fluid loss control agents). Therefore, the spirit and scope of the appended claims should not necessarily be limited to the description of the preferred versions contained herein.