US3245470A - Creating multiple fractures in a subterranean formation - Google Patents

Description

April 12, 1966 K. D. HENRY 3,245,470

CREATING MULTIPLE FRAGTRES IN A SUBTERRANEAN FORMATION' Time fn m/'na /es 400 SOLUB/L/TY @FN/MOGEN 6,95 /N R005 0M WA TER NC 9342A gravi/yo S gl Wafer af 77 F Walle/*07l 2/2 L" (2 S, 1NVENTOR.

0 l l l Kenne/h Q Her/ry 4 8 2 BY WJ Pre 55u/"e in 7%@ sands/0.5.

HTTORNEY K. D. HENRY April l2, 1966 CREATING MULTIPLE FRACTURES IN A SUBTERRANEAN FORMATION 4 Sheets-Sheet 2 Filed Dec.

QCDOONW '0 v j/s'o/ s/ouosnoqi f/ aJ/vssaud INVENTOR.

Kenne 1% D. Henry BY wei ATTOR/VY K. D. HENRY April l2, 1966 CREATING MULTIPLE FRACTURES IN A SUBTERRANEAN FORMATION 4 Sheets-Sheet 3 Filed Dec.

w .KWK

IN VEN TOR. Kenne/6 0. Hen/*g /f/TTOR/VEY K. D. HENRY 3,245,470

CREATING MULTIPLE FRACTURES IN A SUB'IERRANEAN FORMATION April 12, 1966 4 Sheets-Sheet 4 Filed Dec.

.fs-of Soups/7091 U. '9ms-9940 INVENTOR Kenne/? 0. Hen/L9 United States Patent C 3,245,470 CREAHNG MULTIPLE FRACTURES 1N A SUBTERRANEAN FoRMATIoN YKenneth D. Henry, Hamilton, Tex., assignor to The Dow Chemical Company, Midland, Mich., a corporation of Delaware Fied Dec. `17, 1962, Ser. No. 245,156 14 Claims. (Cl. 16e-42) 'tions of Va formation to the wellbore where such flow has vbeen to some extent obstructed by insufiiciently uidpermeable intervening strata.

Fluids, e.g., oil and gas, contained within the voids and pores of a subterranean formation are producede therefrom by fiowing the fiuid out of the formation to a wellbore and lifting it upwardly therethrough either by pressure differential or iiuid displacement or a combination of both.

T o produce fiuid from a formation by either a pressure differential, eg., taking advantage of the natural formation pressure or by pumping, or by fluid displacement, e.g., water fiooding, requires that the formation be huid-permeable at least to some extent. Substantially fluid-impermeable or tight rock structures existing within a fluid-bearing reservoir, e.g., nonporous sills or dikes, or solidified depositions such as sometimes form along slip faults which lie between the fluid-bearing portions of the formation and a wellbore penetrating said formation, block access of the fluid sought to be produced from the wellbore.

Hydraulic fracturing (sometimes supplemented by a treatment of a formation with a chemical which attacks the formation, such as an acid, or by injecting a solid or liquid explosive into the formation and detonating it in place) has been employed to open up connecting passageways through and leading from fluid bearing portions of a formation to a wellbore penetrating the formation.

Hydraulic fracturing, in brief, is conducted by inject- `ing a liquid down a wellbore and forcing it back into the formation at a pressure suicient to lift the overburden or cause cleavage among strata and thus provide cracks and fissures therein. Usually the liquid employed contains a propping agent, e.g., sand, suspended therein, at least Ia part of which lodges in the cracks and fissures so created and helps to prop them open and prevent them from closing'up when the pressure is released. l

One difficulty that has been encountered with hydraulic fracturing is due to the fact that the liquid employed, when forced into a formation, tends to follow the more accessible cracks, fissures, and the like already there or those first created in the early stages of the fracturing operation, rather than to create new cracks or fissures in the formation or to enter the more constricted cracks and fissures in the formation'where fracturing is most needed.

Efforts have, accordingly, been made to divert liquids employed in fracturing into the more constricted openings or to create new openings in preference to following the more readily accessible openings. Such efforts have included the employment of ball Sealers (which are intended to enter perforations in a well casing without passing therethrough) and various plugging, sealing, and bridging lagents on the assumption that such agents will Vbe carried with'the principal iiow of the fracturing liquid as it first enters the formation into the more open channels, some of which will lodge therein, and result in at ICC least 'a partial deterrent of such 'principal'flow, and thereby divert subsequent fracturing liquid into the more con` stricted openings of the formation. Such assumption has proved more-or-less sound and has yielded encouraging returns. However, certain disadvantages have shown up in the use of known plugging and bridging agents in fracturing operations. Among such disadvantages is the fact that such plugging or'bridging occurs relatively close to the wellbore rather than in the more remote portions of the 'form-ation where fracturing is .particularly desirable. A further disadvantage is thatmost of these plugging or bridging agents impart to the fracturing liquid an undesirable increase in viscosity. A still further disadvantage of the use of known pluggingand bridging agents is that when attempting to fracture vertically a relatively thick pay zone, the fracturing fiuid tends -to be dissipated in the upper section thereof and hence the treatment is confined to relatively small sections leaving other relatively large sections of the lpay zone unaffected by the fracturing liquid.

A paramount need exists for a method of fracturing a duid-bearing formation whereby branched and connecting fractures are produced contiguousto the principal and initial fractures so that the uid sought (which Vso often remains locked in the formation some distance from the existing fractures) will find passageway to the wellbore. i

The invention meets this need by providing a method of fracturing a subterranean formation which creates multiple fractures some distance from a wellbore penetrating the formation and which connect with'pre-existing and initially produced fractures thereby making accessible the fluids contained in portions of the formation heretofore remaining largely closed off from fractures made by known methods.

The invention is a method of fracturing a well penetrating a fluid-bearing formation which comprises (l) injecting a fracturing liquid containing a propping agent `dispersed therein down the wellbore of a well penetrating a substerr-anean formation and back into the formation at a generally rising injection pressure until at least one fracture is created in the formation, usually indicated by a detectable cessation of the rise in pressure; (2) incorporating into the fracturing liquid containing the propping agent a substantially inert gas in an amount sufficient to provide a two-phase commingled gas-liquid fluid mixture, at the pressure and temperature conditions existing at the depth of the formation being fractured and continuing to inject the two-phase fiuid mixture, without substantial increase in the rate of injection,

to plug at least partially the fractures created in step y(1);

and (3) substantially repeating step (l) by decreasing the amount of gas incorporated in the fracturing liquid to that which is insufficient to provide a two-phase commingled gas-liquid fluid mixture at the pressure and temperature conditions at the depth of the formation ybeing fractured and continuing to inject the fracturing liquid without substantial decrease in the rate of injection, thereby to provide branched fractures, particularly multiple,

connecting, adventitious-type fractures emanating outwardly from the earlier formed fractures.

It is preferred, but not essential, in the practice` of the invention, that step (3) be followed by a 'further step, designated step (4), which consists substantially of repeating step (2) by increasing the amount of gas incorporated in the fracturing liquid, over that employed in step (3), to that sufficient to insure a two-phase commingled gas-liquid mixture and injecting the mixture into the fractures of the formation. Steps (il) to (4) may be sequentially repeated as often asappears necessary to attain satisfactorily improved results in a particular fracturing operation. Usually the treatment will be terminated when additional fractures do not result or are created only with difliculty or there is a tendency for the propping agent to screen or sand out at the bottom of the wellbore. It is found advantageous in the practice of the invention to decrease the rate of injection of the liquid-gas mixture during step (2), and step (4) when employed, from the rate employed in steps (1) and (3). Suc-h decrease encourages the deposition of propping agent during ysteps (2) and (4). It is also preferred, but not essential in the practice of the invention, that the amount of propping agent be increased in step (2) and step (4) when employed, over that employed in steps (1) and (3). This increases the amount of propping agent which screens out during steps (2) and (4).

Practice of the invention is most conveniently and effectively carried out when some gas is incorporated in the fracturing liquid during all the steps. The-continued flow of gas is more convenient because the pumps ernployed for this purpose may be continued in operation, the amount of gas desired for each step being controlled by merely decreasing or increasing the gas pumping rate. The continued flow is more effective because the compressed gas, present in the fracturing fluid at all times although in Varying amounts) imparts a spring-like characteristic to the gas-liquid mixture under high pressure so that, When the pressure is subsequently released, the gas therein expands and assists in drivingl the fracturing liquid out of the fractures, into the wellbore and, as a result, is more readily bled off from the well, thereby providing a more comple and rapid removel of fracturing liquid and substantially lessening the need for swabbing, often eliminating such need altogether.

Accordingly, in practicing the invention, some gas is also usually used in steps (1) and (3), but in a carefully limited amount. This amount is suicient to .provide a gas-liquid mixture when pressure is reduced to only that resulting from the hydrostatic head (minus loss of pressure due to friction) and not sutiicient to provide enough gas with the liquid to result in screening or sanding out in the fractures of the formation during the fracturing operation. Such amount has been found to be a gas to liquid volume ratio of about 1:4, i.e., not over 1 volume of gas out of 5 volumes of the gas-liquid mixture or a volume ratio of gas to liquid of about 0.2. Hereinafter the term volume ratio will usually be used to refer to a volume ratio of gas to liquid phases at the level or depth of the formation being fractured. On the other hand, a volume ratio of more than 0.2 is employed in step (2), and step (4) when employed, to insure screening out and consequential plugging off of existing or newly created fractures in the formation. The maximum volume ratio employed in steps (2) and (4) is guided only by that amount which tends to screen out in the wellbore itself (as opposed to screening out in the fractures of the formation as desired). The ratio usually observed in step (2) and step (4) when employed, is greater than about 0.2 but usually not greater than about 0.5. In practicing the invention, it should be kept in mind that certain gases are more soluble in some liquids than in others. For example, carbon dioxide, methane, propane, natural gas, and gaseous hydrocarbons generally are much more soluble in liquid hydrocarbons such as crude oil than in water and brine. On the other hand, nitrogen has relatively lower solubility in liquid hydrocarbons. Accordingly, carbon dioxide and gaseous hydrocarbons, although economically feasible for use in liquid hydrocarbons under many oil field conditions, must be employed (when so used) in larger quantities than a gas of the nature of nitrogen. However, carbon dioxide and gaseous hydrocarbons are, in general, as well suited for use in aqueous treating liquids as in nitrogen gas.

The ratio of the amount of gas to that of the liquid in the fracturing mixture is in reference only to the volume of gas which exists therein as free gas, i.e., in a gas phase, e.g., bubbles, undissolved in the liquid at the level of the formation being fractured. Accordingly, the gas which dissolves in the liquid is not included in calculating the ratio. The extent to which a gas dissolves in a liquid, at a given temperature, is largely dependent upon the natures of the liquid and of the gas employed and upon the pressure. For example, organic liquids such as hydrocarbons, dissolve greater proportions of a gas than do aqueous liquids under the same conditions.

Reference to the graphs of the annexed drawing will be of assistance at this point:

In FIGURE 1, the number of standard cubic feet of nitrogen gas necessary to saturate 39 A.P.I. crude oil, per 42-ga1lon barrel, at 77 F. and water at 77 F. and at 212 F. are shown on the ordinate, at increasing pressures shown on the abscissa.

In FIGURE 2, there is set out on the curves, the number of standard cubic feet of free nitrogen gas existing with 39 A.P.I. gravity crude oil at 120 F. when the amount of gas shown on the abscissa is employed, at the pressure shown on the ordinate.

In FIGURE 3, there is set out on the curve. the number of standard cubic feet of free nitrogen gas existing with water at F. when the amount of gas shown on the abscissa is employed, at the pressure shown on the ordinate.

In FIGURE 4, there is set out on the curves, the number of standard cubic feet of free carbon dioxide gas existing with 39 A.P.I. gravity crude oil and in water, both at 120 F., when the amount of gas shown on the abscissa is employed, at the pressure shown on the ordinate.

In FIGURE 5, there is shown a pressure-time curve taken from the chart of the instrument employed to record pressure at the well-head during a treatment according to the invention showing: the pressure rise from zero to the point of fracture followed by a cessation of rise or leveling off representing initial step 1); a tirst dip in pressure during step (2); a second rise in pressure during step (3) which is less marked but attains a higher peak at fracture than that of step (1); a second dip in pressure when step (4); a third rise in pressure when step (1) is repeated attaining a higher peak at fracture than in step (3); a third dip as step (2) is repeated; a fourth rise in pressure attaining a lstill higher peak at fracture than previously attained as step (3) is repeated; a fourth dip as step (4) is repeated; a fifth rise in pressure as step (1) is again repeated attaining a higher peak at fracture than theretofore; a fifth dip as step (2) is repeated; and a iinal rise in pressure up to about 5000 p.s.i. which did not show a cessation in pressure rise and leveling off to indicate a fracture at which time the treatment was discontinued as evidenced by the fall of the pressure to zero.

The solubility of a gas in a liquid by volume is substantially a linear function of the pressure, in accordance with Henrys law, except at extremely high pressures where some deviation from the gas laws occurs. However, for practical purposes, such straight line relationship may be fully relied upon. The substantially straight line relationship may be seen by referring to FIGURE 1 and to the curves designated saturation on FIGURES 2, 3, and 4.

If desired, additional information on the relationship of specific gases in specific kliquids may be obtained from texts and publications on the subject, e.g., Solubilities of Inorganic and Metal Organic Compounds, volume 1 (3rd edition) by Seidel and Solubilities of Gases in Liquids at High Pressure in Industrial and Engineering Chemistry, volume 23, pages 548 to 550, by Per Frolich et al.

The pressure condition existing at the bottom of the wellbore may be readily calculated by recording the injection pressure at the well-head, subtracting therefrom the loss of pressure due to friction, and adding thereto the pressure due to the hydrostatic head. Friction loss tables are readily available for use in this type of calculation, e.g., those contained in Technical Report-Friction Loss Data Bulletin, DWL-1150 (September 1962), available from Dowell Division of The Dow Chemical Company, Tulsa 14, Oklahoma. The pressure of the hydrostatic head is readily calculated by finding the weight of the fluid in the wellbore.

The following descriptive material explains the practice of the invention in some detail:

In step (1), the amount of propping agent employed is usually between about 0.5 and about 3 pounds per gallon of fracturing liquid. Although the presence of gas therein is not essential, it is preferably used in amounts sufficient to provide a volume ratio (as dened above) of at least about 0.1 but not in excess of about 0.2 at the pressure existing at the level of the formation being fractured. The rate of injection of the fracturing liquid containing the propping agent, and gas, if employed, is usually between about 5 and about 60 barrels per minute. The period of time taken up by step (l) is dependent largely on the rate of injection. For example, at the minimum recommended injection rate of 5 barrels per minute, the time taken is usually between about 3 and 10 minutes, and at a maximum recommended rate of injection of about 60 barrels per minute, the time taken by step (1) is usually between about 0.5 and 3 minutes. Recommended periods of time at any intermediate pumping rate can readily be calculated or plotted from those times suggested for the minimum and maximum rate.

In step (2), the amount of the propping agent is usually increased to between about 1.25 and about 4 timesV that employed in step (l), between 1.5 and 3 times as much being preferred. An amount of gas is admixed with the fracturlng liquid or simultaneously pumped down the wellbore to provide a volume ratio which is more than 0.2, preferably at least 0.3, and usually not more than 0.5, thereby causing the propping agent to drop out in the fractures and ssures to effect at least some plugging thereof. The period of time taken up for step (2) is preferably less than that of step (1), usually being on the order of only between about 0.25 and 0.75 as long as that of `step (l), providing the rate of injection of the uid into the well of the two steps is substantially about the same. Best results are obtained, however, if the rate of injection of fracturing liquid into the well is decreased somewhat during step (2). A decrease in such rate supplements the eect of the increased propping agent and gas contents causing the propping agent to drop out of the fluid and lodge in the larger and more accessible cracks and fissures.

In step (3) the amount of gas and usually also the propping agent in the fracturing liquid are reduced to valuessimilar to those of step (1). However, it is preferred that the time taken up by step (3) be somewhat less than that of step (1). It is recommended that it be about the length of time of step (2). It is also recommended that the rate of injection of the uid be increased in step (3) over that of step (2) to create, more effectively, new branched cracks and fissures and to carry the propping agent well back into such newly created cracks and fissures.

In step (4), when employed, the amounts of gas and the propping agent (if decreased in step (3)), are increased to about those of step (2). lt is recommended that the rate of the injection be also reduced to about that of step (2) to aid in the deposition of the sand as desired. It is recommended, however, that the period of time allowed for step (4) be somewhat shorter than that of step (2).

As aforesaid, the four steps can be repeated as often as appears advisable, because the free gas entrapped in the fracturing liquid injected during step (2) lessens the propping agent-carrying capacity of the fracturing uid causing the propping agent to be dropped out in the fractures and fissures, particularly those created in the preceding step (l) which contained little or no gas and was usually injected at higher pressures than employed in step (2.) Propping agent is thus lodged in the more accessible fractures and fissures. Free gas is also left in the more accessible fractures and fissures, following step (2), which gives rise to added resistance to entrance thereinto of additional fracturing fluid injected in subsequent step (3) wherein the gas content of the fracturing fluid is again lessened below that switch provides free gas at the pressure existing at the formation being fractured. The free gas in the fractures thus aid in causing the fractun'ng fluid to by-pass, at least partially, the sand-blocked and gas-occupied larger fractures and ssures and be diverted to portions of the formation which contain fewer or more constricted openings to create fractures therein.

As hereinbefore stated, best results are obtained when step (4) is employed and particularly when steps (1) through (4.) are repeated.

It is preferred to employ some gas in the fracturing uid during the fracturing steps, viz., steps (1) and (3), which is all dissolved, i.e., is not present as a separate phase or as free gas at the pressure existing at the level of the formation being fractured because at least a part of the gas, thus present as dissolved gas during fracturing, is converted to free gas when the pressure is released upon termination of the fracturing operation and at that time serves as a fluid spring which virtually shoots fluid from the fractures and fissures in the direction of the wellbore, and upward therein, thereby greatly lessening the customary swabbing operation following fracturing or eliminating it altogether.

The following examples are illustrative of fracturing ells in accordance with the practice of the invention. All rates and concentrations expressed in the examples refer to the fracturing fluid employed. All ratio values are volume ratios of gas to liquid at the pressure and temperature existing at the depth of the formation being fractured.

EXAMPLE 1 A well having the description given immediately below, was treated.

Location Sojoiner Pool,

Haskill County, Tex. Total depth 5235. Bottom hole temp. F. Casing extending to bottom 5.5" in diameter, containing perforations between 5207.5 and Tubing 2.5 in diameter, 5130 depth (volume about 30 barrels).

Packer Guiberson ltype positioned at 5119', between casing and tubing.

Pumping equipment commonly employed for fracturing operations including sand and fracturing liquid plus a supply of nitrogen gas and pumping equipment therefor were located at the well site. A reocrding instrument for recording injection pressure was positioned at the well-head.

The treatment was carried out as follows:

Preliminary step The well was pressure-tested and then the tubing and annulus, both above and below the packer, were filled with lease oil.

Step 1.-Additional lease oil, containing 270 cubic feet of nitrogen gas per barrel to provide a volume ratio of 0.196, and one pound of sand per gallon of oil, was started down the tubing at a rate of 11 barrels per minute. This is the fracturing liquid. Lease oil already in the tubing and in that portion of the annulus below the packer was thereby forced into the formation. Sand contained in the fracturing fluid began to enter the formation at this time. The pressure chart indicated a surface pressure of about 3800 p.s.i. when a leveling off indicated a fracture had occurred.

Step 2.-The rate of injection was then reduced to about 8 barrels per minute and the injection continued at that rate for 1 minute while the sand content was increased to 2.5 pounds per gallon and the nitrogen gas content increased to 365 cubic feet per barrel thereby providing a volume ratio of 0.31. The injection pressure chart reading was about 3400 p.s.i.

Step 3.-The rate of injection was then increased to 11 barrels per minute and the injection continued at that rate for 41/2 minutes while the nitrogen gas was reduced to 270 cubic feet per barrel, thereby providing a volume ratio of 0.196, and the sand concentration reduced to about one pound per gallon. When an injection pressure of about 3900 p.s.i. was reached; the pressure leveled off indicating a second fracture had occurred.

Step 4.-The rate of injection was then reduced to 8 barrels per minute, and the injection continued at that rate for 1.5 minutes while the sand content was increased to 2.5 pounds per gallon, the nitrogen gas content increased to about 365 cubic feet per barrel to give the volume ratio of 0.196. The injection pressure had fallen to about 3500 p.s.i.

Step 1 substantially repeated-The rate of injection was increased to 11 barrels per minute and the injection continued at that rate for about a minute while the sand content was reduced to 1 pound per gallon, the nitrogen gas content decreased to about 270 cubic feet per barrel, to give the volume ratio of 0.196. The injection pressure had risen to about 4000 p.s.i. when it leveled olf indicating a third fracture.

Step 2 substantially repeated-The rate was then decreased to 8 barrels per minute and the injection continued at that rate for about 1 minute While the sand content was increased to 2.5 pounds per gallon, and the nitrogen gas content increased to about 365 cubic feet per barrel, to give the volume ratio of 0.31. The injection pressure dropped to about 3600 p.s.i.

Step 3 substantially repeated-The rate of injection was increased to 11 barrels per minute and the injection continued at that rate for about 3 minutes while the sand content was reduced to 1 pound per gallon, and the nitrogen gas content decreased to about 270 cubic feet per barrel, to give the volume ratio of 0.196. The injection rate rose to about 4050 when it leveled off indicating a fourth fracture.

Step 4 substantially repeated-The rate of injection was decreased to 8 barrels per minute, and the injection continued at that rate for about a minute while the sand content was increased to 3 pounds per gallon, and the nitrogen gas content increased to about 365 cubic feet per barrel, to give the volume ratio of 0.31. The injection pressured dropped to 3650 p.s.i.

Step 1 substantially repeated- The rate of injection was increased to 11 barrels per minute and the injection continued at that rate for about 1 minute while the sand content was reduced to 1.5 pounds per gallon, the nitrogen gas content decreased to about 270 cubic feet per barrel, to give the volume ratio of 0.196. The injection pressure rose to about 4100 p.s.i. and leveled off indicating a fifth fracture.

Step 2 substantially repeated.-The rate of injection was decreased to 8 barrels per minute and the injection continued at that rate for about 2 minutes while the sand content was increased to 4 pounds per gallon, the nitrogen gas content increased Ito yabout 365 cubic feet per barrel, to give the volume ratio of 0.31. The injection pressure dropped to about 3950 p.s.i.

Step 3 substantially repeated-The rate of injection was then markedly increased, the chart registering the injection pressure showing a top pressure of about 5100 p.s.i. but did not level off thereby indicating that no additional fractures of significance took place. Treatment was complete at this point.

Reference to the chart which recorded the injection pressures showed that each successive fracturing pressure was higher than any preceding one until the treatment was terminated, similarly to the graph of FIGURE 5 of the drawing.

A total of 87,380 cubic feet of nitrogen gas in adrnixture with the sand and lease oil to comprise the fluid fracturing mixture was injected into the we ll during the treatment.

Pressure on the well was then released, the treating uid allowed to flow back out, and pumping of the well resumed. After two days, the entire quantity of fracturing liquid employed in the Well treatment had been recovered (i.e., the load recovery period was two days). This time is clearly in contrast with an average of 6 days required for complete recovery of the fracturing uid employed in all wells, fractured by conventional technique, which were located in the same pay Zone in the same field.

The production of the well so treated was ascertained six days after completion of the treatment and found to be 207 barrels of oil per day. Production before the treatment had been 30 barrels of oil per day. The improvement, again, was in marked contrast to the improvement attained by conventional fracturing of other wells producing from the same zone in the field, the average of such wells after treatment being 130 barrels of oil per day. Fifteen days after treatment, the well treated as described above was producing 250 barrels of oil per day in contrast to wells of the same Zone and field, conventionally treated, which produced an average of 120 barrels per day after fifteen days.

EXAMPLE 2 A second well was fractured in accordance with the method of the invention. As in Example l, all volume ratios are those at the pressure and temperature existing at the depth of the formation being fractured. The well is described as follows:

Location Albion, Michigan. Total depth 4614.

Bottom hole temp. F.

Casing, extending to bottom 5.5 in diameter, perforated between 4142 and 4162. Packer None. Tubing None.

Step 1.-After the well was pressure-tested, water (as the fracturing liuid) was started into the well casing at the rate of 25 barrels per minute and sand was fed into the water in an amount suiicient to provide a proportion of 0.5 pound per gallon; also concurrently, 108 cubic feet of nitrogen gas per barrel was fed into the Water-sand mixture. This amount of nitrogen was a volume of 0.098. The injection was continued at the aforesaid rate for a period of 3 minutes. The injection pressure as recorded at the surface rose to about 2000 p.s.i. where it leveled off indicating a fracture.

Step 2.-The rate of injection of the fracturing liuid was decreased to 20 barrels per minute and the injection continued at that rate for 3 minutes while the nitrogen content was increased to 290 cubic feet per barrel t0 provide a volume ratio of 0.26. The proportion of sand was held substantially constant at 0.5 pound per gallon of fracturing fluid. The injection pressure dropped t0 about 1900 p.s.i.

Step 3.-The rate of injection of the fracturing iuid was increased to 25 barrels per minute and the injection continued at the rate for 4 minutes while the nitrogen content was decreased to 108 cubic feet per barrel to provide a Volume ratio of 0.098. The proportion of sand was held substantially constant at 0.5 pound per gallon 9 of water. The injection pressure'rose to about 2025 p.s.i. and again leveled off indicating a second fracture.

Step 4.-The rate of injection of the water was decreased to 20 barrels per minute and the injection continued at that rate for 2 minutes while the nitrogen content was increased to 290 cubic feet per barrel to provide a volume of 0.260; and the sand proportion was increased to 1 pound per gallon. The injection pressure dropped to about 1925 p.s.i.

Injection of both the sand and the Water at this point was discontinued and only nitrogen gas injected at the rate of 5400 cubic feet per minute for the purpose of flushing fracturing fluid out of the wellbore and further `back into the formation without adding to the burden of swabbing since the gas removes itself, as well as some of 'the liquid when pressure on the well is released.

A total of 310,000 cubic feet nitrogen gas had been used in the entire treatment of Example 2. The pressure was then released on the well and the treating fluid allowed to ilow out. Fourteen hundred barrels of fracturing liquid were recovered from the well in two days. The balance of four hundred barrels were removed by swabbing. This was a distinct advantage over the difiiculty of removing the fracturing load from other wells fractured in the same area which permitted no removal of fracturing liquid by owing the well and all of which had to be removed by swabbing 4The well treated was a non-producer at the time of treatment; it showed a small flow of oil after production.

Comparative ran (not in accordance with the improvement of the invention) A third oil Well was fractured, employing nitrogen gas in the fracturing liquid but in an amount insufiicient to provide a gas to liquid volume ratio of 0.2 at the depth of the formation being fractured at any time during the fracturing treatment. Similar equipment and a surface pressure recording chart were employed as in the above examples. The well had the following description.

Location Sprayberry Trend, Martin County near Stanton, Texas.

Total depth 8107.

Bottom hole temp. 115 F.

Casing 4.5 in diameter, perforated at 4 levels: 2 levels between 7264 and 7280' and 2 levels between 8064 and 8100'.

Tubing 2 in diameter, extending into pay zone.

Step 1.-A low viscosity fuel oil conta-ining 11/2 pounds of sand per gallon and 222 cubic feet of nitrogen gas per barrel to provide a volume ratio (of gas to liquid) at fracturing pressure of 0.07, was injected at the rate of 19.6 barrels per minute for la period of minutes. A fracture was indicated by leveling off the injection pressure as shown on the chart at the well-head at about 3300 p.s.i.

Step 2.--The rate of injection and sand content of the fracturing liqiud were held substantially `constant and the nitrogen gas content decreased to 284 cubic feet per barrel, to provide a gas to liquid volume of 0.116, for a period of 2 minutes. The injection pressure remained substantially at 3300 p.s.i.

Step 3.-The rate of injection and sand content were held substantially constant and the nitrogen gas content was decreased to 194 cubic feet per barrel to provide a volume ratio of 0.065, for a period of 5 minutes. The injection pressure remained substantially at 3300 p.s.i.

Step 4.-The rate of injection and sand content were held substantially constant and the nitrogen gas content was increased to 284 cubic feet per ybarrel (as in step (2)) to provide a volume ratio of 0.116, for a period of 2 minutes. The injection remained substantially at about 3300 p.s.i.

Step 5 (similar to step 1).-The rate of injection and sand content remained unchanged and the nitrogen gas was decreased to 153 cubic feet per barrel to provide a volume ratio of 0.018, for a period of 2 minutes. The injection pressure remained substantially unchanged.

Step 6 (similar to step 2).-The r-ate of injection was held substantially constant but the sand concentration was increased to 4 pounds per gallon and the nitrogen gas content was increased to 284 cubic feet per barrel (as in steps 2 and 4) to provide a volume ratio of 0.116, for a period of 1 minute. The injection pressure remained substantially unchanged.

Step 7 (similar to step 3).-The rate of injection remained substantially the same but the sand content was reduced to lil/z pounds per gallon as in the earlier steps and the nitrogen content was reduced to 173 cubic feet per barrel to provide a volume ratio of 0.022 for 4 minutes. The injection presssure remained substantially unchanged.

Step 8 (similar to step 4).-The rate of injection and nitrogen gas content continued to be maintained substantially the same to provide -a continued volume ratio of 0.022 as in step 7, but the sand content was increased to 6 pounds per gallon. The injection pressure remained substantially at 3300 p.s.i.

Step 9 (similar to step 1).-The rate of injection and the nitrogen content continued unchanged but the sand lcontent was reduced to 1% pounds per gallon, for an injection of 11/2 minutes. The injection pressure remained at substantially 3300 p.s.i.

Step 10 (similar to step 2).--The rate of injection and nitrogen content continued unchanged but the sand content Was increased to 8 pounds per gallon for an injection period of one minute. There was no `change in the injection pressure. The treatment was stopped at this point.

During ythe treatment about 163,420 cubic feet of nitrogen gas were injected into the well.

The entire load of treating uid owed back out of the well following the release of pressure on the well; no swabbing was required. In treat-ment of similar wells in this field, wherein a gas is not employed as in this treatment, swabbing was always required Ato remove the treatment iluid. However, the injection pressures, as shown on the recording cha-rt at the well-head, showed no dips nor showed any evidence of additional fractures following the initial fracture.

The well was put back in production. It showed improved production over that preceding the treatment. However, the extent of improved production was no better than that of a number of other Wells producing from ythe same formation in the same field which had been fractured by known methods.

Reference to Examples 1 and 2 and a study of FIG- URE 5 of the drawing show the improved results obtained by the practice of the invention.

'Having described my invention what I claim and de- 'sire to protect by Letters Patent is:

1. A method lof Vfracturing a well penetrating a fluidbearing subterranean formation comprising the steps of: (1) injecting a fracturing liquid containing a propping agent dispersed therein down the wellbore of the well and back into the formation until at least one 'fracture is created therein;

(2) incorporating into the fracturing liquid containing the .propping agent a gas, which is substantially unreactive with the liquid and with the formation fluids, in an amount sucient to provide an undissolved free gas phase as bubbles within the liquid phase, having a free gas -to liquid volume ratio of more than about 0.2 at the pressure and temperature conditions existing at the depth of the formation being fractured and continuing to inject the twophase Huid mixture, without substantial increase in the rate of injection to plug at least partially'the fractures created in step (1);

(3) substantially repeating (l) by decreasing the amount of gas incorporated in the fracturing liquid to that which will continue to provide a gas-liquid volume ratio, when the pressure is reduced, to only that resulting from the hydrostatic head but which is less than about 0.2 at the pressure and temperature conditions existing at the depth of the formationg being fractured, and continuing to inject the fracturing liquid, without substantial decrease in the 4rate of injection, thereby to provide branched, multiple, connecting adventitious-type fractures emanating outwardly from the earlier formed fractures.

2. The method in accordance with claim 1 wherein the amount of propping agent incorporated in step 2. is increased over that incorporated in claim 1.

3. The method in accordance with claim 1 wherein the rate of injection of step 2 is decreased from that employed in step 1.

4. The method in accordance with with claim 1 Wherein step 3 is followed by step 4 wherein the amount of gas incorporated in the fracturing liquid is increased to au amount sufficient to provide a gas to liquid volume ratio at the pressure and temperature conditions at the `depth. of the formation being fractured of at least 0.2.

5. The method in accordance with claim 4 wherein the rate of injection of the fracturing liquid employed in step 4 is decreased from that employed in step 3.

6. The method in accordance with claim 4 wherein the amount of propping agent employed in step 4 is increased over that employed in step 3.

'7. A method of fracturing a well penetrating a subterrean formation comprising the steps of:

(l) incorporating into a fracturing liquid selected from the group consisting of oil, water, brine, gelled water, oil-water emulsions, and aqueous acid solutions, a particulate inorganic propping agent in an amount of at least about 0.5 pound per gallon of fluid but not in excess of that which results in appreciable screening out thereof in the wellbore, and a substantially inert gas in an amount sufcient to provide a gas to liquid ratio by volume of at least about 0.1 and less than about 0.20, at the pressure and temperature existing at the depth of the formation being fractured, injecting the resulting gas-liquid-propping agent fluid down the well at a rate of injection of between about 5V and 60 barrels per minute, and forcing it back into the formationV at a pressure sufficient to fracture the formation, and continuing to inject said iiuid for a measured period of time at a controlled velocity of injection to force the fluid containing the incorporated propping agent and gas in cracks and fissures;

(2) increasing the amount of gas being incorporated into the fracturing fluid, to an amount sufficient to provide an undissolved free gas phase as bubbles within the liquid phase having a gas to liquid volume ratio at the depth of the formation being fractured, of more than about 0.2, thereby to provide a two-phase free gas and liquid uid containing propping agent, and continuing to inject the fracturing fluid without substantial increase in the rate of injection of said fluid, to accelerate the rate at which propping agent is deposited in fractures in the for-` mation, thereby, `to plug at least partially the cracks and ssures created in the formation included newly created ones;

(3) decreasing the amount of gas being incorporated into the fracturing uid, to an amount suticient to continue to `provide a gas to liquid volume ratio, when the pressure is reduced, to only that resulting from the hydrostatic head but less than about 0.2 at the depth of the formation being fractured, and continuing to inject the gas-liquid-propping agent fluid without substantial decrease in the rate of injection of said uid to create branched, multiple, adventitious-type fractures emanating outwardly from existing fractures;

(4) substantially repeating step (2).

8. The method according to claim 7 wherein steps 1 to 4 therein are sequentially repeated until effective desired fracturing has been fully attained in a particular fracturing treatment as indicated by pressure variations of the fluids being injected.

9. The method according to claim 7 wherein steps 2 and 3 are each carried out for a shorter period of time than step 1, and wherein step 4 is carried out for a shorter period of time than steps 2 and 3.

10. The method according to claim 7 wherein the velocity of injection of the fracturing fluid in steps 2 and 4 is less than the velocity of injection thereof in steps 1 and 3.

11. The method according to claim 7 wherein the propping agent is sand having a mesh size of between 20 and 60, and is employed in an amount of between 0.5 and 3 pounds per gallon of fracturing fluid in steps 1 and 3 and in amount of between 1.5 and 3 times the amount employed in steps l and 3 in steps 2 and 4.

12. The method according to claim l wherein the free undissolved gas is employed in steps 2 and 4 in amount suflicient to provide a volume of gas to liquid of between 0.20 and 0.50.

13. In a method of hydraulically fracturing a well penetrating a subterranean formation the improvement which consists essentially of iirst creating fractures by injecting a liquid down the well and back into the formation at fracturing pressure then injecting a mixture twophase free gas-liquid uid containing a free propping agent suspended therein, having a gas to liquid volume ratio of more than about 0.2 at the pressure and temperature existing at the depth of the formation being fractured, and at a rate of injection which is insufficient -to create fractures, and thereafter reducing the ratio of free gas to liquid in the uid to continue to provide a gas-liquid mixture when the pressure is reduced to only that resulting from the hydrostatic head but which is less than about 0.2 and maintaining a rate of injection which is suiciently high to create multiple branched fractures emanating outwardly from the fractures already created.

14. The method according to claim 13 wherein the ratio of free gas to liquid in said fluid is alternately repreatedly raised to above 0.2, with an accompanying decrease in injection rate, and reduced to below 0.2 with an accompanying increase in injection rate.

References Cited by the Examiner UNITED STATES PATENTS 2,347,769 5/1944 Crites 166- 7 X 2,888,988 6/1959 Clark 166-42.1 X 3,004,594 10/1961 Crawford 166/42.1 3,063,499 11/1962 Allen l66/42.1

...CHARLES E. OCONNELL, Primary Examiner,

UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No. 3,245,470 April 12, 1966 Kenneth D. Henry It is hereby certified that error appears in the above numbered patent requiring correction and that the said Letters Patent should read as corrected below.

Column l, line I9, for "producede" read produced column 3 line 3l for "comple" read vcomplete column 4 line 22, for "curve." read curves, line 4l, for "when step" read during step column 6, line 8, for "switch" read which line 6l, for "reocrding read recording column 8, line 57, after "volume" insert ratio line 72, for "at the" read at that column l0, line 44, for "treatment" read treating column ll, line 3, after "repeating" insert step lines 9 and l0, for "formationg" read formation line 54, for "in" read into column l2, lines 30 and 34, before "amount", each occurrence, insert an line 40, after "pressure" insert and line 4l, strike out free"; line 4Z, before "gas" insert free line 55, for "repreatedly" read repeatedly Signed and sealed this lst day of August 1967.

(SEAL) Attest:

EDWARD M. FLETCHER, JR. EDWARD J. BRENNER Attesting Officer Commissioner of Patents

Claims (1)

1. A METHOD OF FRACTURING A WELL PENETRATING A FLUIDBEARING SUBTERRANEAN FORMATION COMPRISING THE STEPS OF: (1) INJECTING A FRACTURING LIQUID CONTAINING A PROPPING AGENT DISPERSED THEREIN DOWN THE WELLBORE OF THE WELL AND BACK INTO THE FORMATION UNTIL AT LEAST ONE FRACTURE IS CREATED THEREIN; (2) INCORPORATING INTO THE FRACTURING LIQUID CONTAINING THE PROPPING AGENT A GAS, WHICH IS SUBSTANTIALLY UNREACTIVE WITH THE LIQUID AND WITH THE FORMATION FLUIDS, IN AN AMOUNT SUFFICIENT TO PROVIDE AN UNDISSOLVED FREE GAS PHASE AS BUBBLES WITHIN THE LIQUID PHASE, HAVING A FREE GAS TO LIQUID VOLUME RATIO OF MORE THAN ABOUT 0.2 AT THE PRESSURE AND TEMPERATURE CONDITIONS EXISTING AT THE DEPTH OF THE FORMATION BEING FRACTURED AND CONTINUING TO INJECT THE TWOPHASE FLUID MIXTURE, WITHOUT SUBSTANTIAL INCREASE IN THE RATE OF INJECTION TO PLUG AT LEAST PARTIALLY THE FRACTURES CREATED IN STEP (1); (3) SUBSTANTIALLY REPEATING (1) BY DECREASING THE AMOUNT OF GAS INCORPORATED IN THE FRACTURING LIQUID TO THAT WHICH WILL CONTINUE TO PROVIDE A GAS-LIQUID VOLUME RATIO, WHEN THE PRESSURE TIS REDUCED, TO ONLY THAT RESULTING FROM THE HYDROSTATIC HEAD BUT WHICH IS LESS THAN ABOUT 0.2 AT THE PRESSURE AND TEMPERATURE CONDITIONS EXISTING AT THE DEPTH OF THE FORMATION BEING FRACTURED, AND CONTINUING TO INJECT THE FRACTURING LIQUID, WITHOUT SUBSTANTIAL DECREASE IN THE RATE OF INJECTION, THEREBY TO PROVIDE BRANCHED, MULTIPLE, CONNECTING ADVENTITIOUS-TYPE FRACTURES EMANATING OUTWARDLY FROM THE EARLIER FORMED FRACTURES.

Images