Process Of Hydraulic Fracturing With Viscous Oil-in-water Emulsion

Abstract

A method for the hydraulic fracturing of a subterranean formation wherein an oil-in-water emulsion containing a heavy crude oil, petroleum fraction, or similar hydrocarbon oil having a viscosity in excess of about 1500 centipoises at 100.degree. F. is injected into a well at a rate sufficient to open a fracture in the exposed formation.

Parent Case Text

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of Ser. No. 655,356, filed July 24, 1967, and now abandoned, which is in turn a continuation-in-part of Ser. No. 421,578, filed Dec. 28, 1964, and now abandoned, and Ser. No. 641,275, filed May 25, 1967, now U.S. Pat. 3,378,074.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the hydraulic fracturing of subterranean formations surrounding oil wells, gas wells, and similar boreholes.

2. Description of the Prior Art

Hydraulic fracturing has been widely used for stimulating the production of crude oil and natural gas from wells completed in low permeability formations. The methods normally employed require the injection of a fracturing fluid containing a suspended propping agent into a well under sufficient pressure to open a fracture in the exposed formation. Continued pumping of fluid into the well at a high rate extends the fracture and leads to the buildup of a bed or propping agent particles between the fracture walls. These particles prevent complete closure of the fracture as the fluid subsequently leaks off into the adjacent formation and result in permeable channels extending from the wellbore into the formation. The conductivities of these channels depend upon the fracture dimensions, the size of the propping agent particles, the particle spacing, and the confining pressures. Equations which can be used to compute the fracture dimensions and conductivities that will be obtained under particular operating conditions have been published in the technical literature and will be familiar to those skilled in the art.

The fluids used in hydraulic fracturing operations must have filter loss values sufficiently low to permit buildup and maintenance of the required pressures at reasonable injection rates. This normally requires that such fluids either have high viscosities or contain filter loss control agents which will plug the pores in the formation. Although the use of "low penetrating fluids" with viscosities of 5,000 centipoises or higher at atmospheric temperature has been proposed, much less viscous fluids are generally used. Typical fluids include crude oils and petroleum fractions having viscosities up to about 200 centipoises at atmospheric temperature; gelled hydrocarbons containing aluminum soaps, polymers and similar thickening agents, temporary emulsions prepared with kerosene, diesel fuel, and similar light hydrocarbons, and aqueous solutions containing polymers and other additives. The filter loss values of such fluids are generally high unless they contain filter loss control agents or other additives which tend to plug the pores in the formation. Many of the materials used as thickeners or gelling agents have this ability. In the absence of such materials, silica flour, lime, talc, guar gum, hydrocarbon resins, or similar agents are normally added to reduce the filter loss values.

The use of fracturing fluids having relatively low viscosities in conjunction with filter loss control agents is advantageous in that it avoids excessive friction losses in the tubing and casing. The wellhead pressures and hydraulic horsepower required to overcome such friction losses may otherwise be prohibitive. Gelled fluids prepared with water, kerosene, and similar low-viscosity liquids are particularly useful in this respect. Such fluids have apparent viscosities sufficient to permit pumping of the propping agent particles and yet shear down in contact with the tubing or casing wall to give low friction losses. The gelling agents also promote laminar flow under conditions where turbulent flow would otherwise take place and hence in some cases the losses may be lower than those obtained with the low viscosity base fluids containing no additives. Certain water soluble polyacrylamides, oil-soluble polyisobutylenes and other polymers which have little effect on viscosity when used in low concentrations can be added to the ungelled fluids to achieve similar benefits.

The trend in fracturing in recent years has been toward the use of gelled fluids which have viscosities sufficient to permit pumping of the propping agent particles and which contain filter loss control agents designed to provide the required low penetrating properties as described above. The propping agents employed include quartz sand grains, tempered glass beads, rounded walnut shell fragments, aluminum pellets, and similar materials. These agents are generally used in concentrations between about one and about four pounds per gallon. The permeability obtained with such a material is roughly proportional to the square of the particle diameter and hence the use of particles up to about 4 mesh on the U.S. Sieve Series scale has been suggested. In practice, however, propping agents with particle sizes of 20 to 40 mesh or smaller are generally employed. At the injection rates used with such fluids, generally between about 10 and about 50 barrels per minute, such particles can generally be pumped satisfactorily in fluids with viscosities from about 10 to about 30 centipoises. Where very high rates are used, the particles are often used with plain water or other fluids of lower viscosity.

The use of larger propping agent particles to secure higher fracture conductivities as outlined above has been hampered by difficulties in injecting the larger sized particles. Experience has shown that particles greater than about 20 mesh will frequently bridge across the mouth of the fracture and begin to accumulate in the wellbore. This is referred to as a "screenout." Once such an accumulation commences, the entire operation generally has to be terminated, even though only a small fraction of the required propping agent has been placed. Because of the frequency with which difficulties are encountered when the larger particles are used, most operators prefer to employ 20 to 40 mesh or smaller particles.

The productivity improvement obtained as a result of fracturing depends upon the contrast between the conductivity of the fracture and the permeability of the formation and upon the fracture length-to-radius of drainage ratio. In zones of very low permeability, a relatively short fracture of low conductivity may permit a two-to three-fold improvement in the fluid production rate. In a more permeable formation, on the other hand, such a fracture may result in only a small increase in production or may not be successful at all. Because of the poor response in the more permeable zones, conventional fracturing operations have generally been confined to severely damaged wells or wells completed in undamaged formations having permeabilities below about 15 to 20 millidarcies. Most such operations are carried out in wells with permeabilities in the one to ten millidarcy range.

The incentives for developing fractures with conductivities sufficient to permit the application of fracturing to high permeability reservoirs are substantial. The low permeability formations in which conventional methods are used generally produce at low rates and hence total production remains low even though an improvement of severalfold is obtained. In reservoirs of higher permeability, the initial production rates are normally much higher and hence a successful fracturing operation may produce a much greater improvement in terms of incremental barrels of oil per day. This is true even though the percentage improvement may be somewhat smaller than in a reservoir of lower permeability. Efforts to extend fracturing operations to undamaged reservoirs with permeabilities substantially in excess of about 15 to 20 millidarcies have in the past been largely unsuccessful.

SUMMARY OF THE INVENTION

This invention provides an improved fracturing method which at least partially alleviates the difficulties outlined above. The method of the invention involves the injection of a viscous oil-in-water emulsion or suspension containing a heavy crude oil, petroleum fraction, or similar hydrocarbon oil having a viscosity in excess of about 1,500 centipoises at 100.degree.F. into a well at a rate sufficient to open a fracture in the exposed formation. Injection of the emulsion or suspension is continued until a fracture of sufficient dynamic width and length to produce a highly conductive channel has been formed. Particles of a propping agent, suspended in the emulsion or suspension or in a later-injected fluid, are used to prevent complete closure of the fracture. The injected fluids are then permitted to leak off into the formation until the fracture has closed sufficiently to hold the particles in place. Thereafter, the fluids remaining in the fracture may be produced back into the wellbore. This method permits the generation of fractures with substantially higher conductivities and greater fracture length-to-radius of drainage ratios than have generally been obtained heretofore, results in greater productivity improvements than do conventional methods, ad permits the application of fracturing to wells not readily susceptible to treatment by conventional fracturing methods.

The mechanisms responsible for the improved results obtained in accordance with the invention are not fully understood. It has been found, however, that loose oil-in-water emulsions or suspensions prepared with heavy crude oils, petroleum fractions or similar hydrocarbon oils having viscosities in excess of about 1,500 centipoises at atmospheric temperature can be injected through the tubing or casing without excessive friction losses and that these fluids permit the formation of much wider and longer fractures than can generally be obtained with the light hydrocarbon emulsions or suspensions employed in the past. Water contacting the formation during injection of the emulsion or suspension apparently permeates into the reservoir rock, leaving heavy oil in contact with the rock surface. This heavy oil leaks off into the formation very slowly and at the same time results in a relatively high pressure drop within the fracture. The wider, longer fractures which are thus obtained with the emulsions or suspensions and the concurrent use of larger propping agent particles than have generally been practical in the past provide higher conductivities and greater fracture length-to-radius of drainage ratios than have generally been obtained heretofore. Although other mechanisms may also be involved, studies indicate that these particular mechanisms play important roles.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 in the drawing is a graph which shows the settling rate of typical propping agent particles in fracturing fluids of various viscosities;

FIG. 2 is a graph illustrating the effect of fluid viscosity on filter loss control agents; and

FIG. 3 is a graph showing the effect of changes in temperature on typical heavy oils that may be employed in preparing the fracturing fluids used for purposes of the invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The fracturing process of this invention involves the use of oil-in-water emulsions or suspensions that permit the generation of fractures with higher conductivity contrasts and larger effective fracture length-to-radius of drainage ratios than have generally been obtained with oil-in-water emulsions or suspensions employed in the past. The process is based in part upon studies which indicate that much of the water initially present in an oil-in-water emulsion prepared with a heavy oil is quickly lost to the surrounding formation after such a fluid enters a fracture. The mobility of water in the rock matrix is generally higher than the mobility of the heavy oil and hence the oil initially present as the dispersed phase tends to remain behind and become the continuous phase. Even though substantial quantities of water may be present, the viscosity of the remaining fluid will generally be similar to that of the oil itself. This oil must have the ability to transport large propping agent particles over relatively long distances if high conductivity contrasts and large effective fracture length-to-radius of drainage ratios are to be obtained.

The ability of a fracturing fluid to transport propping agent particles depends in part upon the rate at which the particles settle out of the fluid within the fracture. FIG. 1 in the drawing is a plot of the single particle settling rate for quartz sand propping agent particles of various sizes in Newtonion fluids. Similar plots can be prepared for other particle-fluid systems. The curves of FIG. 1 show that the particle settling rate is an inverse function of the fracturing fluid viscosity and indicate that oils having viscosities of about 25 centipoises or higher at formation temperature are necessary if low settling rates are to be obtained with the 20--40 mesh or larger sand grains, glass beads, or similar propping agent particles generally employed. At atmospheric temperatures between about 30.degree.F. and about 100.degree. F., such oils will generally have viscosities of 1,500 centipoises or higher.

In addition to being able to transport relatively large propping agent particles effectively, the oils employed for purposes of this invention must have filter loss values sufficiently low to permit the generation of fractures having the required dynamic dimensions. This will often necessitate the use of filter loss control agents. Experience has shown that the effectiveness of such agents depends upon the viscosities of the fluids in which they are used. This is illustrated in FIG. 2 of the drawing, which is a plot of the filter loss coefficients, D.sub.w, obtained with a typical filter loss control agent in oils of various viscosities. The curves of FIG. 2 show that the full benefits of the filter loss control agents are not obtained with low viscosity fluids and that the viscosity of the oil employed should be 25 centipoises or higher at formation temperature. As pointed out above, this will normally require the use of oils having viscosities of 1,500 centipoises or higher at atmospheric temperatures.

A variety of different crude oils, petroleum fractions, and similar hydrocarbon oils having viscosities in excess of about 1,500 centipoises at normal atmospheric temperatures can be employed for preparing the oil-in-water emulsions or suspensions used in accordance with the invention. Suitable hydrocarbon oils include high viscosity crude oils, vacuum still residual fractions, heavy lube oil stocks, low pour point residual heating oils, extracts from the solvent extraction of lubricating oils, bright stocks, straight run asphalts, low temperature Gilsonite, and similar oils with viscosities between about 1,500 centipoises and about 20 million centipoises at temperatures in the range between about 30.degree.F. and about 100.degree.F. Heavy oils having viscosities of 5,000 centipoises or higher are generally preferred. Oils with viscosities greater than about 3,000 centipoises at atmospheric temperature are often difficult to handle with conventional pumping equipment and may therefore be heated prior to preparation of the emulsions or suspensions. The viscosities of typical heavy oils at various temperatures are illustrated in FIG. 3 of the drawing. A typical crude oil of moderate viscosity is shown for purposes of comparison.

As pointed out above, the heavy oils employed for purposes of the invention may be used in conjunction with filter loss control agents. If such agents are not used, the oils selected will preferably have viscosities at formation temperatures equal to or greater than those defined by the equation ##SPC1## where .mu. is the viscosity of the crude oil or petroleum fraction at formation temperature in centipoises, k is the permeability of the formation to the crude oil or petroleum fraction in millidarcies, .phi. is the porosity of the formation expressed as a decimal fraction, and P.sub.c is the difference between fluid pressure in the fracture and the formation pressure in pounds per square inch. The fluid pressure in the fracture can be determined by multiplying the fracture gradient in pounds per square inch per foot of depth by the depth in feet and adding the friction drop within the fracture. The fracture gradient is a measure of the pressure required to break down the formation and is normally between about o.7 and about 0.9 pounds per square inch per foot of depth. The friction drop in the fracture can be calculated by means of equations found in the literature if certain assumptions are made but for purposes of this invention it is generally satisfactory to assume a friction drop of 1,000 pounds per square inch. The viscosities determined by means of this equation can be translated into viscosities at atmospheric temperatures through the use of viscosity-temperature charts similar to that shown in FIG. 3 of the drawing.

Except in shallow formations of low permeability where the reservoir temperatures are quite low, it will generally be necessary to employ oils with viscosities well above 1,500 centipoises at 100.degree.F. to obtain the viscosities required at formation temperatures by the equation set forth above. In typical formations with permeabilities in the 1-to 10-millidarcy range for example, the use of heavy oils with viscosities in the range between about 1,500 centipoises and about 5,000 centipoises at atmospheric temperature is generally satisfactory but in formations with higher permeabilities, crude oils, heavy petroleum fractions, and similar oils having viscosities in the range between about 5,000 centipoises and about 25,000 centipoises at atmospheric temperature are usually more effective. Where the permeability and temperature are both high, crude oils, residual petroleum fractions, or similar hydrocarbon oils having viscosities well in excess of 25,000 centipoises at atmospheric temperature may be necessary to secure the desired fracture dimensions. Oils with viscosities in excess of about 100,000 centipoises at atmospheric temperature are particularly effective in wells of this latter type.

A variety of different commercially available surface active agents may be employed in preparing the emulsions or suspensions utilized for purposes of the invention. These include alkyl esters of sodium sulfosuccinic acid, alkali metal salts of alkylaryl benzene sulfonic acids, soluble salts of alkyl naphthalene sulfonic acids, alkyl esters of polyalkylene glycols, polyalkylene esters of fatty acids, polyoxyalkylene anhydrosorbitol esters of fatty acids, long chain amine hydrochlorides, alkylene oxide-amine condensation products, alkylene oxide-alkylphenol condensation products, long chain carboxylic acids and mixtures of such materials. All of these surfactants are not equally effective for purposes of the invention and hence certain agents described in greater detail hereafter are generally preferred.

The surfactant concentration required will depend in part upon the particular agent selected, the oil to be employed, the salinity of the water to be used, and the relative amounts of oil and water to be employed. In general, however, surfactant concentrations between about 0.005 percent and about 5 percent by weight will be satisfactory. The optimum concentration for a particular surfactant and a particular oil-water system can be readily determined by mixing the surfactant with the oil and the water in various concentrations and observing whether suitably viscous emulsions or suspension of the desired water-external type are formed.

The water-external emulsions or suspensions used in accordance with the invention are generally prepared by adding a mixture of a long chain alkyl or aryl sulfonate and a polyoxyethylated glycol or a similar water-soluble surface active agent to water or brine in a concentration of from about 0.05 to about 2 percent by weight, mixing the resultant solution thoroughly, and then adding a heavy solvent neutral extract from the manufacture of lubricating oil or a similar heavy oil having a viscosity in excess of about 1,500 centipoises at 100.degree. F. to the solution with agitation until a mixture of from about 50 to about 90 volume percent oil and from about 10 to 50 volume percent water is obtained. The use of from 50 to 80 percent oil and from 20 to 50 percent water is preferred. Thorough mixing as the oil is added results in a viscous emulsion which has low filter properties, supports most propping agents for long periods without perceptible settling, and can be pumped with low friction losses. It is usually preferred to mix these emulsions or suspensions by circulating the fluids through the pumps until a smooth uniform dispersion is obtained but other mixing methods may be used.

In lieu of adding the surfactant to the water as described above, it is sometimes preferred to dissolve the surface active agent in the oil prior to the introduction of any water. Laboratory work has shown that certain surface active agents will not readily permit the preparation of oil-in-water emulsions or suspensions if the surfactant is initially present in the water but may perform satisfactorily if added to the oil first. Since the behavior of the surfactant may be affected by natural surface active agents present in the oil and by ions in the water or brine, it is normally advantageous to prepare sample emulsions containing the oil, water and surface active agent in various concentrations in the laboratory before undertaking the preparation of large volumes of an emulsion for use in the field. Such laboratory tests provide a convenient means for readily determining the optimum concentrations in which particular constituents should be used.

Other surface active agents which are particularly useful for preparing water-external emulsions containing the heavy oils include alkyl trimethyl diamines such as tallow trimethyl diamine, alkyl trimethyl diamine-ethylene oxide condensation products such as tallow trimethyl diamine condensed with 15 moles of ethylene oxide, quaternary ammonium halides such as dicocodimethyl ammonium chloride, and the like. Emulsifiers of this type are often employed for the preparation of water-external emulsions containing heavy oils by heating the water to be used to a temperature of about 120.degree. F., adding concentrated hydrochloric acid to the water in a concentration between about0.01 an about 0.5 percent, based on the total weight of water and oil to be employed, mixing into the resultant acid solution from about 0.01 to about 0.05 percent of the emulsifier, again based on the total weight of water and oil to be used, and then blending the heavy oil and emulsifier solution in the desired proportions with vigorous agitation. The heavy oil may be heated to a temperature of 120.degree. F. or more to facilitate the blending. The use of hydrochloric acid to convert the emulsifier to the hydrochloride salt is not always necessary but frequently simplifies the preparation of such emulsions.

The water-external emulsions or suspensions prepared as described above may have apparent viscosities somewhat less than those of the heavy oils employed in preparing them but the viscosity obtained will depend on the relative amounts of oil and water present and the shear rate in the system. Such emulsions will normally contain at least 50 percent of the heavy oil by volume and will preferably contain less than 80 percent oil by volume. Because the heavy oil thus normally constitutes the major constituent of the water-external systems, the apparent viscosities of the emulsions or suspensions at low shear rates will generally approach those of the heavy oils. These fluids have non Newtonian characteristics and hence the emulsion viscosities tend to decrease with increasing shear rates.

It will be understood that the compositions set forth above are typical of those that may be employed for purposes of the invention but that other oils with viscosities in excess of about 1,500 centipoises and other surface active agents may be employed. Because of the effect of salts on most ionic surfactants, certain anionic and cationic surfactants may be suitable for use with brines, while others are not. In certain cases the oils employed may contain oxygen, nitrogen, and sulfur compounds and other natural surface active agents in concentrations sufficient to permit the formation of suitable emulsions without the addition of surfactants to the system. Film strengtheners, viscosity index improvers, inorganic salts, inhibitors and other additives may be incorporated in the oil or water used in preparing the emulsions if desired.

In carrying out the invention, the emulsion or suspension to be employed is normally prepared by mixing water or brine containing a suitable surface active agent with a viscous crude oil, petroleum fraction, or similar hydrocarbon oil having a viscosity in excess of about 1,500 centipoises at atmospheric temperature. This will generally be done at the well site as described above. In lieu of this, the fluid may be formulated at a refinery or similar plant and transported to the well site in a tank truck, barge or the like. In either case, the fluid will generally be pumped into one or more tanks connected to a blender of conventional design. The blender is generally provided with jets and a ribbon mixer to facilitate the introduction of a propping agent into the fluid as it is injected and is operated at high speed to prevent buildup and "slugging" of the propping agent particles. If it does not include a ribbon mixer, extra jets may be installed and connected to the blender pump or to an auxiliary pump to insure sufficient agitation. Discharge lines from the blender extend to high pressure positive displacement triplex pumps which are connected in parallel and driven by diesel engines or turbines. The pump discharge lines in turn are manifolded to an injection line which extends to the wellhead. All of the equipment thus employed may be of the type utilized in conventional fracturing operations.

After the emulsion has been delivered to the well site or prepared on location and circulated for a short time to insure a proper mixture, the lines in the system are filled with fluid and pressure tested in the conventional manner. it is often preferred to break down the formation with water or a light oil before injecting the viscous fracturing fluid and hence water or oil may be first pumped into the well through the tubing or casing. A packer will normally be used to isolate the formation to be fractured. Injection of the water or oil is continued at a high rate until a pressure sufficient to break down the formation and initiate a fracture is obtained. The generation of this fracture will normally be indicated by a sharp drop in pressure. As soon as this occurs, injection of the viscous emulsion or suspension to be used as the fracturing fluid is commenced. After the emulsion or suspension is flowing into the fracture satisfactorily, the propping agent can be added to the fluid at the blender.

The propping agent is generally added to the emulsion or suspension in amounts sufficient to give a propping agent particle concentration between about one-fourth and about 20 pounds per gallon. The concentration used will depend in part upon whether a partial monolayer, a concentration near the lower end of the range will normally be employed; whereas a considerably higher concentration will ordinarily be used to produce a fully packed fracture. Propping agent concentrations well above those feasible in conventional operations can be used if desired. Sand will ordinarily be employed as the propping agent in relatively shallow wells up to about 7500 feet but in deeper wells it may be advantageous to employ glass beads, steel shot or other materials capable of withstanding higher confining loads than ordinary sand. Regardless of the agent selected, the propping agent used will normally have a particle size between about 4 mesh and about 40 mesh on the U.S. Sieve Series scale. Particles in the 8-to 12-mesh size range are usually preferred. The use of particles less than about 12 mesh in size frequently precludes maximum productivity improvements except in formations of very low permeability.

The viscous emulsion or suspension containing suspended propping agent particles passes through the tubing or casing into the fracture. The friction losses will generally be low because the water constitutes the external phase of the emulsion. As the emulsion or suspension enters the fracture, water contacting the exposed formation rapidly permeates into the porous rock. As water is lost, the emulsion may invert. The viscous oil or resulting oil-external emulsion has low dynamic filter loss characteristics and therefore remains in the fracture, serving to propagate it. This highly viscous fluid produces a relatively high-pressure drop within the fracture and permits the generation of a much wider and longer fracture than can normally be obtained with gelled fluids or viscous emulsions prepared with kerosene, diesel fuel or crude oils of moderate viscosity.

After the required quantity of emulsion or suspension and propping agent has been injected into the formation, the blender and fracturing pumps are shut down. Water or crude oil may be flushed through the equipment and into the tubing to clean out any heavy emulsion or suspension remaining. The water or oil should not be injected into the fracture itself. The well is then closed and allowed to stand, generally for 24 hours or longer. As the injected fluid slowly leaks off into the adjacent formation, the fracture closes on the propping agent particles so that they are held in place. After the pressure has been bled off, the injected fluid may be produced back into the wellbore. Dilution by oil from the formation normally accelerates production of the heavy oil employed in preparing the emulsion. Lease crude oil, kerosene, diesel fuel or the like can be injected into the casing to dilute the heavy oil further and facilitate its removal from the well. Small amounts of propping agent may be dislodged from the face of the fracture when the well is first returned to production but the amount of this material produced will not normally be sufficient to create any serious production problems.

Although the propping agent will normally be suspended in the viscous emulsion or suspension as described above, this is not always essential. Instead, the emulsion or suspension may be employed to open a wide fracture in the formation and a second fluid which is less viscous and contains the propping agent can then be injected. The later injected fluid containing the propping agent apparently fingers into the viscous emulsion or heavy oil remaining in the fracture and thus permits placement of the propping agent. Some narrowing of the fracture may occur as the fluid containing the propping agent is injected but this may not always be the case. This use of two stages has been found advantageous for the fracturing of water injection wells and gas wells where it is desired to limit the quantity of viscous fluid remaining in the fracture at the end of the treatment and thus accelerate the resumption of normal operations. In lieu of this procedure, a low viscosity fluid miscible with the highly viscous oil can be injected in front of the emulsion or suspension so that the viscosity of the heavy oils will be reduced by dilution when injection or production is resumed. Diluents can in some cases also be injected after completion of the fracturing operation.

A further modification of the invention involves injection of the viscous emulsion or suspension into the well at a rate insufficient to generate a fracture until essentially all of the low viscosity connate fluids present in the wellbore have been displaced into the formation and the pressure behavior at the surface indicates that the emulsion is in contact with the formation. At this point, the injection rate can be rapidly increased to build up the pressure and generate the required fracture. Field tests have shown that this procedure can be employed in shallow wells to generate vertical fractures under conditions such that horizontal fractures might otherwise tend to be formed.

It will be understood from the foregoing that the invention is not restricted to the specific formulations set forth above and that other water-external emulsions or suspensions containing hydrocarbon oils with viscosities in excess of about 1,500 centipoises at atmospheric temperature may be employed. Oils other than those specifically mentioned above which have viscosities in excess of about 1,500 centipoises at 100.degree. F. including dewaxed or deasphalted oils, oils derived from coal tar or oil shale, and synthetic oils, can also be used. A variety of different surface active agents, including materials which permit breaking of the emulsion or suspension after the fracture has closed and compositions designed to promote inversion to an oil-external system as the fluid passes through the perforations or loses water to the formation, may be employed.

Claims

I claim:

1. A method for the hydraulic fracturing of a subterranean formation surrounding a wellbore which comprises injecting a viscous oil-in-water emulsion containing a hydrocarbon oil having a viscosity in excess of about 1,500 centipoises at 100.degree. F. as the oil phase into said wellbore at a rate sufficient to open a fracture in said formation and thereafter producing said hydrocarbon oil from said fracture into the wellbore.

2. A method as defined by claim 1 wherein said oil has a viscosity in excess of about 5,000 centipoises at 100.degree.F.

3. A method as defined by claim 1 wherein said emulsion contains from about 50 to about 90 volume percent of said hydrocarbon oil and from about 50 to about 10 volume percent water.

4. A method as defined by claim 1 wherein said hydrocarbon oil is a lube oil extract with a viscosity at atmospheric temperature in excess of about 100,000 centipoises.

5. A method as defined by claim 1 wherein said hydrocarbon oil is a residual petroleum fraction.

6. A method for the hydraulic fracturing of a subterranean formation exposed within a wellbore which comprises injecting into said wellbore a water-external emulsion containing from about 50 to about 80 percent by volume of a hydrocarbon oil having a viscosity in excess of about 1,500 centipoises at 100.degree. F. and from about 20 to about 50 percent by volume of water, applying sufficient pressure to said emulsion to open a fracture in said exposed formation, and thereafter producing said hydrocarbon oil from said fracture into said wellbore.

7. A method as defined by claim 6 wherein said hydrocarbon oil has a viscosity in excess of about 25,000 centipoises at atmospheric temperature.

8. A method as defined by claim 6 wherein said hydrocarbon oil is a heavy extract obtained from the manufacture of lubricating oil.

9. A method for propping a fracture in a subterranean formation exposed with a wellbore which comprise generating a fracture in said exposed formation; injecting an oil-in-water emulsion and a propping agent suspended in said emulsion into said fracture, said emulsion containing a hydrocarbon oil having a viscosity in excess of about 1,500 centipoises at 100.degree. F. as the oil phase; and thereafter producing said hydrocarbon oil from said fracture into the wellbore.

10. A method as defined by claim 9 wherein said hydrocarbon oil has a viscosity in excess of about 25,000 centipoises at atmospheric temperature.

11. A method as defined by claim 9 wherein said hydrocarbon oil has a viscosity at formation temperature equal to or greater than that defined by the equation ##SPC2## where .mu. is the viscosity in centipoises at formation temperature, .kappa. is the permeability of the formation to said oil in millidarcies, .phi. is the porosity of the formation expressed as a decimal fraction, and P.sub.c is the difference between the fluid pressure in the fracture and the formation pressure in pounds per square inch.

12. A method as defined by claim 9 wherein said hydrocarbon oil is a straight run petroleum asphalt.