GB2050467A

GB2050467A - Fracturing Subterranean Formations

Info

Publication number: GB2050467A
Application number: GB7919835A
Authority: GB
Original assignee: Individual
Current assignee: Individual
Priority date: 1979-06-07
Filing date: 1979-06-07
Publication date: 1981-01-07
Also published as: GB2050467B

Abstract

A method is provided for hydraulically fracturing a subterranean formation in which a fracture is first induced in the formation and then subjected to multiple hydraulic fracturing cycles to generate vertical linear fractures or to extend the fracture zone radially outwards from the point of introduction of the fracturing fluid into a well penetrating the formation. By utilizing a plurality of carrier stages of fracturing fluid containing a high ratio of fine proppant and injected at a low rate (compared to conventional techniques) and alternating with the carrier stages a plurality of spacer stages of fracturing fluid without proppant, linear fracturing solely within the formation can be substantially increased with very little or no radial vertical fracturing occurring outside the formation.

Description

SPECIFICATION Fracing Process This invention relates to hydraulic fracturing, or fracing, of earth formations, and more particularly to the hydraulic fracturing of hydrocarbon bearing formations, such as oil and gas sands, for the purpose of increasing the production rate and total amount of recovery of the hydrocarbons from a well completed in such a formation.

Hydraulic fracturing techniques for hydrocarbon formations are well known and have been extensively used for increasing the recovery of oil and gas from hydrocarbon bearing formations. These techniques involve injecting a fracing fluid down the well bore and into contact with the formation to be fractured. Sufficiently high pressure is applied to the fracing fluid to initiate and propagate a fracture into the formation. Propping materials are generally entrained in the fracing fluid and deposited in the fracture to maintain the fracture open during production.

The function of fracturing is to overcome the deficiency in permeability of the formation adjacent the well bore by creating a highly conductive path reaching out into the producing formation sand and/or rock surrounding the well bore. According to the usual practice, a fluid, such as water, oil, oil/water emulsion, gelled water or gelled oil is pumped down a well bore with sufficient pressure to open a fracture in the formation. The fracing fluid may carry a suitable propping agent (also known as a proppant), such as sand, glass beads, etc., for the purpose of holding the fracture open after the fracturing fluid has been recovered, e.g., allowing the well to flow.In the case of tight or low permeability wells, that is, wells below one millidarcy permeability, prior art methods of fracturing have produced results that are of but a temporary nature as far as increasing the rate of flow is concerned.

After perhaps a short period of accelerated flow, rates of production may drop off to near previous levels. Repeated stimulation with the same or a similar procedure may again produce but a temporary gain.

One of the reasons for such a lack of results in a low permeability formation is that at the depths encountered most formations have a preferred vertical fracture orientation which exists because of naturally occurring planes of weakness in the formation as the fracture is formed and are propagated along these planes of weakness. It has been found that these vertical fractures are most advantageous in formations having a relatively wide pay zone and a permeability of the order of 10 to 20 millidarcys.

Unfortunately, many geological oil and gas bearing formations, including some West Texas formations, which are primarily gas formations, comprise multiple, vertically-spaced narrow pay zones, that is 1 0-to-30 foot pay zone formations, each separated generally by a shale layer. Further, the pay zones are formed in sandstone and have a very low permeability, on the order of 10 to 0.1 millidarcy or less. To further complicate recovery, the pay zones contain contaminants, such as water sensitive clays and iron; which react unfavorably with acids often used in treating the formation.

Using a conventional fracing process, vertical fracturing occurs as above-described. In a gas well of the above-described multiple pay zone type, this results in radial vertical fracturing that extends between the pay zones and through the intervening shale zones. As a result, fracing fluid is lost into the shale zones with no resulting benefit in fracturing the hydrocarbon pay zones.

Additionally, only small vertically oriented radial fractures are created in the pay zones and because of the deep vertical orientation do not permit much radial penetration horizontally into the pay zone itself. A temporary increase in production produced by the vertical fractures is believed to be the result of the fracture permitting communication between the well bore in a small portion of a joint system between the matrix elements of the formation and with a small portion of the reservoir matrix.

However, as soon as this low volume space has been drained, productivity drops off to that controlled by the low permeability reservoir matrix, and since the formation area exposed to such matrix by the short radial vertical fractures is small, productivity is low.

An object of the present invention is to overcome or at the very least ameliorate the disadvantages of the prior art by providing a method for fracturing a producing formation to produce generally vertical linear fractures extending outwardly from a borehole over a wide radial extent within the zone of interest, with a minimization of radial vertically oriented fractures occurring above and below the producing zone of interest.

According to the present invention, there is provided a method of forming fractures, generally vertical linear fractures, in a subterranean producing formation extending outwardly from a well penetrating the formation without forming any substantial radial vertical fracturing of overlying or underlying strata, comprising the steps of introducing into said well, in a multiplicity of stages, a proppant-laden fracing fluid carrying a fine-sized proppant material in an average proppant-to-fluid ratio of at least four pounds per U.S. gallon, introducing between said stages of proppant-laden fracing fluid a spacer stage of fracing fluid without proppant, said proppant-laden fracing fluid and said spacer fracing fluid being injected at an injection rate of not more than 25 barrels per minute and at a pressure selected for producing said vertical linear fracture in the formation, the introduction of said proppant-laden fracing fluid continuing until at least 25,000 pounds of said fine proppant material have been deposited in the formation fracture for each one-foot of available net producing formation. Thus the invention is directed to a method for forming long vertical linear fractures which extend outwardly from the borehole in a producing zone with a minimization of radial vertical fracturing penetrating into the intervening layers, e.g. of shale.The process comprises multiple fracing stages carrying a fine proppant which is preferably sand of between 60 to 1 40 mesh size (preferred average 100 mesh) in a high proppant-to-fluid ratio mix, i.e., 4 Ibs/gal.

or higher. Preferably, the proppant-to-fluid ratio is at least eight pounds per gallon, the particularly preferred range being from eight to twenty pounds of fine proppant per U.S. gallon of fracing fluid. Each carrier stage is immediately followed by a corresponding spacer stage comprising the fracing fluid without a proppant added. Immediately following the final carrier stage and corresponding spacer stage, it is preferred to employ a terminating stage in which fracing fluid carrying a medium-sized proppant is injected; the medium-sized proppant is advantageously sand of a 20-90 mesh size, more preferably of a 20 to 40 mesh size. The terminating stage can be followed by a fracing fluid flush of the tubing string. The fracing fluid can comprise water, KCI, a gel and alcohol.Additionally, the fracing fluid may be made up of up to 70% alcohol by volume, advantageously from 25% to 70%, in order to reduce the water volume of the fracing fluid which may adversely react with water-sensitive clays within the formation. Further, liquified CO2 (carbon dioxide), generally up to 20% by volume, may be combined with the frac water/alcohol mixture to reduce further the water volume for the abovementioned reason and, in addition, to reduce the "wet" qualities of the liquid injected into the formation. The preferred quantity of liquified CO2 is from 10% to 20% by volume.

The injection rate for both proppant-laden fracing fluid stages and spacer stages is preferably not more than 25 barrels per minute. The proppant-carrying fracing fluid is preferably injected at a rate of from 2 to 20 barrels per minute, more preferably from 9 to 15 barrels per minute.

As above mentioned, most formations have a preferred vertical fracture orientation along naturally occurring planes of weakness. Therefore, it is usually anticipated that vertical fracturing will occur in the formation. However, although a "fracture" will have a generally "vertical" orientation, the plane angle of the propagating fracture may vary greatly in the formation as the planes of formation weakness vary. A fracture may begin as a substantially vertical fracture and end as a substantially horizontal fracture, or begin as a horizontal (pancake) fracture and dip or twist to a more vertical orientation at a further radial distance from the borehole. Accordingly, in the present disclosure, the term "vertical" when referring to vertical fracturing will include all other possible orientations of the fracture in addition to the preferred vertical orientation.

It is thus a feature of the present invention to provide a method of creating fractures over a wide radial extent within relatively thin hydrocarbon formations while substantially eliminating vertical fractures extending into the overlying and underlying shale or other non-producing formations.

The present invention also provides a fracing fluid containing a minimum water content which will adversely react with water-sensitive clays entrapped in the producing formations.

By using the method of the present invention, it may be possible to create vertical linear fractures within a thin producing formation that extend radially outwardly from the well much further than those produced by prior art methods, therefore exposing a much larger vertical area of the formation. The method of the present invention also enables the insertion of several times the amount of solids into the formation for use as "propping agents" than heretofore has been injected using conventional fracing techniques.

The time for a pressure disturbance, that is, a pressure drop initiated by a producing well, to be propagated radially from the well bore through a low permeability earth formation, may be such that it may take a 20-year period to drain the 14.6-acre area reached by the pressure wave front. Further extension will show that it will take the pressure wave 21.5 years to reach the perimeter of a 320-acre square centered on the wall bore, and that the volume extending horizontally over such an area would be drainable in 430 years. The pressure wave would take 34 years in the case of a 640-acre tract (one square mile) which would be drainable in 680 years.

It will be apparent from the foregoing that in order to produce a low permeability field within a 20-year period, the well spacing would have to be approximately 900 feet. However, many states have statutes governing well densities in oil and gas fields. It can be seen that it would be impractical economically to produce a well in such a low permeability formation without special producing techniques.

To speed up recovery from low permeability fields, techniques have been developed in the prior art directed to producing radial fractures in the formation which act as drainage channels to permit the production fluid to drain to the well. Generally, a high volume of fracing fluid, of the order of 5,000 or more gallons per stage, is pumped into the formation at a high input rate, in the range of 25 to 50 barrels per minute.

Additionally, various propping agents have been utilized to maintain the fractures created in an open position after the fracturing pressure has been released. Reference to a "medium" size proppant generally means a proppant having a mesh size falling within the range of 20 to 40. Further, reference to a "fine" size proppant generally means a proppant having a mesh size falling within the range of 60 to 140. The above-mentioned definitions are not to be construed as limitations on the invention, as other proppant sizes may be equally effective in realizing the objectives of the invention. Among such propping agents used in the prior art is "medium" sand (20 to 40 mesh), used in preferance to "fine" sand (60 to 140 mesh) in the belief that the fine sand would pack too tightly and actually cause the fracture-proppant volume to have a permeability lower than the formation.Generally, a low ratio of proppants to fracing fluid (such as 1/2 to 2 Ibs. of sand per gallon of fluid) was utilised.

When used with a single, relatively thick, medium permeability pay zone, conventional fracing techniques developed in the prior art have proved adequate. However, when the conventional fracing techniques are used to fracture low permeability, relatively thin formations, such as found in several gas-sand areas in West Texas, the resulting production has been much less than expected, as will be hereinafter explained.

For a better understanding of the invention, and to show how a specific embodiment thereof may be carried into effect, compared to a prior art method, reference will now be made, by way of example, to the accompanying drawings, in which: Figure 1 is a cross-sectional view illustrating a borehole penetrating an oil or gas bearing formation for introducing a fracing fluid into contact with the formation, and in particular shows the radial vertical fracturing orientation of multiple pay zones and intervening non-producing formations occurring from conventional fracing techiques; Figure 2 is a cross-sectional view of a borehole extending into a multiple pay zone hydrocarbon bearing formation and illustrates the vertical linear fractures created over a considerable radial distance through use of the present invention;; Figure 3 is a vertical cross-sectional view of a typical vertical linear fracture in the pay zone shown in Figure 2 as taken along lines 3-3 of Figure 2; and Figure 4 is a vertical cross-sectional view of a typical radial vertical fracture produced by prior art methods as taken along lines 4-4 of Figure 1.

Referring now to Figure 1, conventional hydraulic fracturing techniques utilize a well 10, having casing 12 extending through an overburden 14 into multiple gas-sand pay zones 16, with the pay zones 1 6 being separated by non-oil or gas bearing strata, such as shale layers 1 8. A number of perforations 20 are conventionally formed in casing 1 2 extending into the pay zones 1 6. Further, a pump 22 connected by tubing 24 to a source of a sand and fracing fluid mixtures 26 pumps the fracing fluid mix into the casing 12 through tubing 28 where, as pressure builds up within casing 12, the fluid is forced out through perforations 20 into the producing formations creating fractures 30.Due to the high input rate, the pressure builds up rapidly extending the radial vertical fractures 30 in pay zones 1 6 through intervening non-producing formations 1 8. As a result, a large quantity of the fracing fluid and sand is deposited in fractures in zones and strata where there is no oil or gas. Additionally, the vertical extending formation of fractures 30 into upper and lower formations tends to limit the radiallextent of the vertical fractures to an average distance "X". As a result, the short radial vertical fractures within the producing formation expose only a limited area of the formation 1 6, resulting in production for only a relatively short time and further production must depend on the slow natural drainage through the low permeability of the formation into the fracture and then to the well bore.

By means of the present invention, vertical linear fractures extending outwards from the well casing over a considerable radial distance into a desired producing formation with substantially no vertically oriented fractures extending into overlying or underlying non-producing formations are obtained as will be hereinafter described. Referring now to Figure 2, the same reference numbers used for Figure 1 have been used to identify similar components for simplicity. Accordingly, well 10 is shown to include casing 12 extending through overburden 14 into multiple gas-sand pay zones 16, which are separated by intervening shale layers 1 8. Pump 22 is shown connected to a source of sand and fracing fluid mixture 26 by tubing 24 and pumps the proppant-laden fracing fluid into the tubing (not shown) within casing 1 2 through piping 28.Conventional techniques are utilized to perforate the casing 12 adjacent a single pay zone 1 6 as shown by perforations 20.

Thereafter, the perforated section of the casing is isolated in order that as the fracing fluid is injected, it only affects the single pay zone. In one embodiment of the invention, a relatively low volume of fracing fluid (2,000 to 5,000 gallons per stage) with a high ratio of solids (in this case, sand), such as 4 to 10 Ibs. (or greater) of sand per gallon of fracing fluid is injected into the single pay zone 16. A low input rate (such as 9 to 1 5 barrels per minute) is used which results in the ability to use a 2 to 3-inch tubing for the fracing fluid injection, as opposed to a much larger casing which must be utilised in the conventional fracing method because of the high input rates.Further, the pressure required to fracture the formation is confined to the tubing and the casing adjacent the formation, reducing the surface area on which the pressure must be maintained.

As will be hereinafter described, multiple stages of proppant-laden fracing fluid alternated with corresponding unladen fracing fluid stages are injected causing vertically oriented fractures 50 to extend iinearly outward for a radial extent defined by "Y" with little or no radial vertical fracturing occurring outside of the treated pay zone 16. The increased surface area of formation 1 6 exposed to the greater radial extent of fractures 50 substantially increases production. Further, by confining fracturing to a single formation, an increased efficiency of production is obtained from that pay zone, without drawing from other zones simultaneously. Once the lowermost formation 16 has been depleted, then the casing 12 would be plugged to seal off the already produced formation and a higher formation would be treated and produced as hereinabove described.

As previously described, prior art fracing processes utilised in such thin multiple pay zones 1 6 only obtained fractures 30 having a radial length "X" and a "propped" width "B" (see Figure 4) of 0.10 inches or less, often in the range of 0.0625 inches utilising a "medium" proppant 35. Utilizing the process of the present invention, a fracture 50 having a length "Y" (as compared to "X") can be obtained, with a "propped" width "A" (see Figure 3) of approximately 0.25 inches utilizing a "Fine" proppant 37. As hereinabove described, the greater the radial extent Y of the linear fracture 50 can be made, the greater the producing formation 1 6 vertical cross-sectional area will be exposed to the fracture 50 to form a low pressure channel to the casing 12, thereby increasing productivity from the pay zone.As can be seen from Figures 1 and 2, a certain cross-sectional area of formation 16 is exposed to fractures 30 and 50. Fracture 50 can often be at least 2-5 times the length of fracture 30, i.e. Y can be 2 to 5 times as great as X, thereby increasing the total vertical cross-sectional area exposed to the fracture by at least 200500% with corresponding increases in productivity. In one test well in which 1,000,000 pounds of proppant (fine sand) was deposited in the formation fracture utilizing the process of this invention, logs and other test data indicated a probable linear fracture of over 2,000 feet wholly within the gas formation.

The methods of the invention can be carried out by any conventional apparatus used for previously known methods of hydraulic fracturing. Thus, suitable apparatus is shown in both Figure 1, the prior art, and Figure 2 of this application. The fracturing fluid can be injected through the well tubing, casing or other available or suitable pipe or conduit, and may be flowed back into a pit or into the fracturing fluid tank. The fluid can be injected through perforations in the casing extending through the cement and directly into the formation, the injection being confined to a selected horizontal thin formation through conventional isolation techniques. Additionally, conventional proppant/water mixing equipment and pumping equipment may be utilised in performing the method.

The fracturing fluid preferably used in carrying out the method of the present invention is a 23% KCI (potassium chloride) water containing conventional gels to increase its viscosity, and is mixed with liquified carbon dioxide (CO2) in predetermined ratios, advantageously preselected from the range of 10% to 20% CO2 by volume. The CO2 is maintained at --100F. until combined with the KCI water in mixer 26 just prior to the fracing fluid being pumped into well 12. During injection the CO2 remains liquified since it is under pressure, and only after the temperature reaches 850F. at the fracing pressures in the formation does the CO2 change to gaseous form. This change to a gas has two benefits. One benefit is the additional energy (when the CO2 gasifies) which assists in removing frac water from the well bore.A second benefit is the reduction of "wet" fluid injected into the formation which must be recovered.

Since many of the producing formations encountered in the multiple pay zone areas of West Texas include water sensitive clays, it is advantageous to reduce the amount of water injected into the formation. In addition to the conventional reduction of water by the above-mentioned addition of CO2, water used in the fracing fluid may be further reduced by the addition of a suitable alcohol in predetermined ratios of up to 70% alcohol by volume of the total fracing fluid. A suitable alcohol for purposes of this application is defined as any alcohol which will reduce the surface tension of the remaining water to enhance pumping of the fracing fluid and, equally important, is miscible with water.

By way of example, 57,000 gallons of the preferred fracing fluid could be made up utilizing 13,680 gallons of sand, 11,400 gallons of liquified Cho,, 8,880 gallons of H20 and 23,040 gallons of methanol or isopropyl or other suitable alcohol. Further, the use of fracing fluid combined with alcohol and CO2 within the ratios above-described has lead to the recovery of injected fluids in ranges of 80 to 95%.

The injection time depends on the volume of fracing fluid to be injected-which is determined by how large a fracture is desired and is calculated in advance-and upon the flow rate, which depends on the pressure and flow resistance. Further, the total injection time will be the sum of the injection times for the various multiple stages.

The following is an example of an experimental well stimulation treatment carried out in accordance with the invention in a West Texas gas field: Example Formation Thickness 28' Depth: 7082' to 7110' Materials: 3% KCI water pius 20% by volume CO2 and including a base fluid gel having a density of 40#/gal. gelling agent Propping Agent: Sand, average 100 mesh, 488,600 Ibs.

and 20/40 mesh 51,000 Ibs.

Casing: 4-1/2" O.D.

Tubing: 2-7/8;' O.D.

Perforations: 22 Pressure Average on casing 1500 Ibs.

Average on tubing 5500 Ibs.

Hydraulic Horsepower Used: 2022 Average Rates in barrels per minute 1 5 Number of stages 40 Volumes: Pre PAD 10,000 gal.

PAD 7,000 gal.

Proppant Laden Fluid 66,000 gal.

Displacement 1,000 gal.

Total Fluid 84,000 Volume Event Rate (Incremental Pressure (pail Description of No. (hum) Volume) (Tubing) (Casing) Operation i Material 1 Test Line 2 0-15 7000 0-5000 1500 Pump Pad 3 15 3000 5200 1500 Start sand 4 ppg 4 15 500 5400 1500 Pump Spacer' 5 16 3000 5100 1500 Start sand at 6 ppg 6 10 500 5400 1500 Pump Spacer 7 1 6 3000 5200 1 500 Start sand at 8 ppg 8 15 500 5200 1500 Pump Spacer 9 15 3000 5200 1500 Start sand at 8 ppg 10 15 1000 5300 1500 Pump Spacer 11 15 3000 5200 1500 Start sand at 10 ppg 12 15 500 5400 1500 Pump.Start 13 15 3000 5200 1500 Start sand at 10 ppg 14 1 5 500 5200 1500 Pump Spacer 1 5 15 3000 5300 1 500 Start sand at 10 ppg 16 15 500 5300 1500 Pump Spacer 17 15 3000 5500 1500 Start sand at 10 ppg 18 15 500 5500 1500 Pump Spacer 19 13 3000 5500 1500 Start sand at 10 ppg 20 13 500 6400 1500 Pump Spacer 21 13 3000 5400 1500 Start sand at 10 ppg 22 13 500 6400 1500 Pump Spacer 23 13-15 3000 6400 1500 Start sand at 10 ppg 24 15 500 5100 1500 Pump Spacer 25 15 3000 5600 1500 Start sand at 10 ppg 26 15 500 5400 1500 Pump Spacer 27 15 3000 5100 1500 Start sand at10ppg 28 15 500 5200 1500 Pump Spacer 29 15 3000 5400 1500 Startsandat 10ppg 30 14 500 5700 1500 Pump Spacer 31 14 3000 5700 1500 Start sand at 10 ppg 32 14 500 6400 1500 Pump Spacer 33 13 500 6300 1 500 Start sand at 10 ppg 34 14 500 6100 1500 Pump Spacer 35 14 3000 5700 1500 Start sand at 10 ppg 36 14 500 5500 1500 Pump Spacer 37 14 3000 5500 1500 Start sand at 10 ppg 38 15 1000 5500 1500 Spacer 39 12000 5500 1500 20--40 sand at 3 ppg The 488,600 Ibs. of average 100 mesh sand was injected at a ratio of 10 lbs./gal. in all but the first four sand stages, while the larger 20-40 mesh sand was injected at 3 Ibs./gal.

In a typical fracing treatment, it has been found desirable to average at least an 8-lb./gal. solids ratio of the "fine" proppant (preferably 60--140 mesh) to fracing fluids. A solids ratio of 12 Ibs./gal.

has been achieved, but with more advanced blending equipment, solids ratios of 1 5-20 Ibs./gal.

should be possible. Of course, a proppant of any suitable size can be utilised if the objectives of the invention are achieved. The final proppant applications were made utilizing a "medium" mesh sand (20-40 mesh), other sizes of final proppant could be utilised, however.

The preferred injection rate is in the range of 10-1 5 barrels per minute, however, a range of 21 5 barrels per minute has been utilised to obtain satisfactory results and rates of 25 barrels per minute or below may produce preferred results depending on the geology of the pay zone. In field tests, the volume of proppant injected into the producing formation has varied from 200,000 Ibs. to 1,000,000 Ibs. of proppant in a single pay zone, utilising fracing fluid volumes of approximately 50,000 gallons to 200,000 gallons, respectively, for overall average solids ratios of 7 to 8 Ibs/gal. In practicing the invention successfully, it has been found that a ratio of at least 25,000 Ibs. of proppant per one (1) foot of net pay zone thickness is generally desirable and can be achieved.

The embodiments described above are illustrative of the invention, and the invention is not limited thereto.

Claims

1. A method of forming fractures, generally vertical linear fractures, in a subterranean producing formation extending outwardly from a well penetrating the formation without forming any substantial radial vertical fracturing of overlying or underlying strata, comprising the steps of introducing into said well, in a multiplicity of stages, a proppant-laden fracing fluid carrying a fine-sized proppant material in an average proppant-to-fluid ratio of at least four pounds per U.S. gallon, introducing between said stages of proppant-laden fracing fluid a spacer stage of fracing fluid without proppant, said proppantladen fracing fluid and said spacer fracing fluid being injected at an injection rate of not more than 25 barrels per minute and at a pressure selected for producing said vertical linear fracture in the formation, the introduction of said proppant-laden fracing fluid continuing until at least 25,000 pounds of said fine proppant material have been deposited in the formation fracture for each one-foot of available net producing formation.

2. A method according to claim 1, wherein the average proppant-to-fluid ratio in the fracing fluid carrying a fine-sized proppant is at least eight pounds per U.S. gallon.

3. A method according to claim 1 to 2, wherein a terminal stage of said fracing fluid carrying a medium-sized proppant material in a proppant-to-fluid ratio less than said fine-sized proppant material proppant-to-fluid ratio is introduced into said fractures for depositing said medium-sized proppant material in the formation adjacent the well bore.

4. A method according to claim 3, wherein said medium-sized proppant material is 20-90 mesh sand.

5. A method according to claim 4, wherein said medium-sized proppant material is 20-40 mesh sand.

6. A method according to any preceding claim, wherein said fine-sized proppant material is 60 140 mesh sand.

7. A method according to any preceding claim, wherein said fracing fluid comprises water, KCI, a gel and an alcohol which is miscible with water.

8. A method according to claim, 7, wherein said fracing fluid comprises 25% to 70% alcohol by volume.

9. A method according to any preceding claim, wherein said fracing fluid injection rate is from 2 to 20 barrels per minute.

10. A method according to claim 9, wherein said fracing fluid injection rate is from 9 to 1 5 barrels per minute.

11. A method according to any preceding claim, wherein the proppant-to-fluid ratio used with said fine-sized proppant material is in the range of 8 to 20 pounds of proppant per gallon of fracing fluid.

12. A method according to any preceding claim, wherein the volume of proppant-laden fracing fluid injected in each stage is from 2,000 to 5,000 U.S. gallons.

13. A method according to any preceding claim, wherein said fracing fluid comprises a combination of KCI water, gel, an alcohol which is miscible with water, and liquefied CO2.

14. A method according to claim 7, 8 or 13, wherein the alcohol comprises methanol or isopropanol.

1 5. A method according to claim 7, 8, 1 3 or 14, wherein the fracing fluid comprises 10% to 20% (by volume) liquified CO2.

1 6. A method as claimed in any preceding claim, wherein said carrier stage injection rate is from 2 to 20 barrels per minute.

17. A method according to claim 16, wherein the carrier stage injection rate is from 9 to 1 5 barrels per minute.

18. A method of forming fractures in a subterranean producing formation extending outwardly from a well penetrating the formation without forming any substantial radial vertical fracturing of overlying or underlying strata, comprising the steps of: (a) introducing a plurality of carrier stages of fracing fluid carrying a fine-sized proppant material in an average proppant-to-fluid ratio of at least eight pounds per gallon, said carrier stage fracing fluid being injected at an injection rate below 25 barrels per minute and at a pressure selected for producing the fractures in the formation; (b) introducing a plurality of spacer stages of said fracing fluid, alternating with said carrier stages, at a selected pressure and rate sufficient to carry said carrier stage proppant material into said fracture and away from said well; and (c) introducing a terminal stage of said fracing fluid carrying a medium-sized proppant material in a proppant-to-fluid ratio less than said carrier stage ratio, said terminal stage being injected at a selected pressure and rate sufficient to carry said terminal stage sand into said fractures adjacent said injection well bore.

1 9. A method according to any preceding claim, wherein introduction of said fracing fluid is continued to achieve a proppant volume of at least 25,000 pounds of said fine-sized proppant material deposited into the formation fracture for each one-foot of vertical net pay zone of the formation.

20. A method according to claim 1, and substantially as hereinbefore described.

21. A method of forming fractures in a subterranean formation, substantially as hereinbefore described with reference to, and as illustrated by, Figures 2 and 3 of the accompanying drawings.