Periodate fracturing fluid viscosity breakers

Fracturing fluids for hydraulically fracturing oil and gas bearing subterranean formations to increase flow of formation fluids into wells using a periodate or a metaperiodate salt as the viscosity breaker. The fracturing fluids are particularly advantageous when used in conjunction with curable resin-coated proppants and for fracturing subterranean formations which are at temperatures between about 50.degree. F. and about 120.degree. F., in conjunction with both uncured resin-coated proppants and other types of proppants.

BACKGROUND 
1. Field 
This invention relates generally to fluids and procedures for hydraulically 
fracturing subterranean formations to stimulate production of crude oil 
and natural gas from wells. More specifically, this invention relates to 
chemical agents called "breakers" which are added to fracturing fluids to 
reduce the viscosity of fracturing fluids when the fracturing procedure is 
completed. 
2. Background Art 
Crude oil and natural gas residing in subterranean porous formations are 
produced by drilling wells into the formations. Oil and/or natural gas 
flow into the well driven by the pressure gradient which exists between 
the formation and the well, gravity drainage, fluid displacement, and 
capillary action. Typically, surface pumps are required to supplement the 
natural driving forces to bring the hydrocarbons to the wellhead surface. 
Most wells are hydraulically fractured to increase flow. The drill pipe 
casing section adjacent to the zone to be fractured is perforated using 
explosive charges or water jets. Then a fracturing fluid is pumped down 
the drill pipe at a rate and pressure high enough to fracture the 
formation. The fractures propagate from the well bore radially outward 
forming either or both vertical and horizontal cracks. Most fractures form 
vertical cracks in formations. 
Solid particles called proppants are dispersed into the fracturing fluid. 
Proppants lodge in the cracks and hold them open after fracturing fluid 
hydraulic pressure is released and the fracturing fluid flows back into 
the well. Without proppants, the cracks would close and the increased 
permeability gained by the fracturing operation would be lost. To preclude 
the cracks from closing prematurely, proppants must have sufficient 
compressive strength to resist crushing, but also-must be sufficiently 
abrasion resistant and non-angular to preclude imbedding into the 
formation. The type and size of propping agents are usually selected to 
complement the characteristics of the formation being fractured. 
In formations under moderate pressure, 6000 psi or less, the most commonly 
used propping agent is ordinary screened river sand. Special grades of 
silica sand are used. For formations with closure stresses above about 
6000 psi, resin-coated sand proppants are preferred. These are high 
quality silica sands which have been coated with a thermoset phenolic 
resin. The resin coating imparts an optimum crush resistance and 
compressibility to the sand particles to optimize propping action. There 
are two types of resin coatings: those that cure in-situ; and those that 
are precured. Curable coatings generally are used where proppant flow-back 
can occur. 
Fracturing fluids are water-based compositions containing a hydratable high 
molecular weight polymeric gelling material which increases the viscosity 
of the fluid. The fluid must be thickened to reduce leakage from the 
fracture fissures during fracturing and to suspend the proppant. A wide 
variety of hydratable viscosifiers are used in fracturing fluid 
formulations including polysaccharides, polyacrylamides and polyacrylamide 
copolymers. Polysaccharides are currently favored. Particularly desirable 
polysaccharides include galactomannan gums, derivatives thereof, and 
cellulose derivatives. Specific polysaccharides include guar gum, locust 
bean gum, carboxymethylguar, hydroxyethylguar, hydroxypropylguar, 
carboxymethylhydroxypropylguar, carboxymethylhydroxyethylguar, sodium 
hydroxymethyl cellulose, sodium-hydroxymethyl cellulose, sodium 
carboxymethylhydroxyethyl cellulose, and hydroxyethyl cellulose. 
Generally, the molecular weights of the hydratable polymers used in 
fracturing fluids range from about 500,000 to about 3,000,000. The ratio 
of apparent viscosity of the fracturing fluid relative to water at shear 
rates encountered in well fractures is between about 500 to 1000. 
The amount of viscosifier employed depends on the desired working viscosity 
of the fluid and the downhole temperature of the formation to be 
fractured. Typically, from about 10 to 100 lbs of viscosifier per 1000 
gallons of fracturing fluid is employed. 
Viscosity generally decreases with temperature, so the viscosifier 
concentration would have to be increased to achieve a required viscosity 
in the formation. However, the amount of thickener required can make the 
fracturing fluid difficult to formulate and pump. Crosslinking the 
polysaccharide provides a better solution. Polysaccharides contain 
hydroxyl groups in the cis form on adjacent carbon atoms which can be 
crosslinked to increase fracturing fluid viscosity. Crosslinking is 
particularly useful for fracturing higher temperature formations, those 
over 200.degree. F. 
Common crosslinking agents include polyvalent ions in their high valance 
state such as Ti(IV) and Zr(IV). Also, borate ions are effective 
crosslinkers for polysaccharides. 
When the fracturing operation is complete, the fracturing fluid must be 
expelled from the fissures so that production of oil or gas can begin. The 
viscosity of the fracturing fluid preferably is reduced ("broken") so that 
it can flow back out of the fissures and into the well. Hydratable 
polymers may decompose spontaneously in time from either bacteriological 
or thermal degradation. But, at formation temperatures below about 
225.degree. F., the natural degradation is too slow and too much 
production time is lost. Accordingly, for wells below about 225.degree. 
F., a chemical agent referred to as a "breaker" is added to the fracturing 
fluid to accelerate viscosity reduction. Breakers operate by breaking the 
backbone chain of the hydrated polymer. Breakers may be added to the 
fracturing fluid at the surface "on-the-fly" as the fluid is being pumped 
down the well. Ideally, the breaker should be dormant until the fracturing 
operation has been completed, and then the breaker should rapidly reduce 
the fluid viscosity. Enzyme breakers such as alpha and beta amylases, 
amyloglucosidase, oligoglucosidase invertase, maltase, cellulase, and 
hemicellulose are commonly used for wells having a bottomhole temperature 
below about 150.degree. F. and with fracturing fluids with pH between 
about 3.5 and 8. Enzymes catalyze the hydrolysis of glycosidic bonds 
between the monomer units of polysaccharides. 
Peroxygen compounds are the preferred breakers for higher temperature 
formations. They form free radicals which break the backbone of gel 
polymer chains. Peroxides generally decompose over a narrow temperature 
range characteristic of the peroxide. Accordingly, premature viscosity 
breaking generally may be precluded by selecting a peroxygen with a 
decomposition temperature close to the temperature in the fractured 
formation so that peroxide does not decompose until it is heated to 
formation temperature. Commonly used peroxygen breakers include 
dichromates, permanganates, peroxydisulfates, sodium perborate, sodium 
carbonate peroxide, hydrogen peroxide, tertiarybutylhydroperoxide, 
potassium diperphosphate, and ammonium and alkali metal salts of 
dipersulfuric acid. Typical breaker addition rates range from about 2 to 
10 lbs. per thousand gallons of fracturing fluid. 
The most common oxidative breakers are peroxydisulfates (S.sub.2 O.sub.8 
.dbd.) which decompose into highly reactive sulfate radical anions. 
Decomposition is slow below 120.degree. F., but can be accelerated by 
adding amines. Peroxydisulfates decompose rapidly above 125.degree. F. The 
amount of peroxydisulfate required decreases with increasing formation 
temperature. As little as 0.25 lb per 1000 gal is required at 200.degree. 
F. 
For higher temperature formations, peroxygens with correspondingly higher 
decomposition temperatures could be used. 
Other chemicals added to fracturing fluids include bactericides to repress 
bacteria growth, oxygen, or free radical scavengers, such as methanol or 
sodium thiosulfate, to inhibit premature breaking, and a surfactant to 
repress foaming. 
It has been observed that curable resin-coated proppants may interfere with 
the viscosity breaking action of peroxy breakers in fracturing fluids 
incorporating polysaccharide viscosifiers. For example, a ten-fold 
increase in the addition rate of persulfate breaker is required when using 
a curable resin-coated sand proppant relative to the amount required when 
using uncoated sand or bauxite proppant. 
It is also known that enzyme and peroxygen breakers do not effectively 
reduce the viscosity of fracturing fluids incorporating polysaccharide 
viscosifiers in formations which are at low to moderate temperatures, that 
is, temperatures from about 50.degree. F. to about 120.degree. F. The low 
temperature viscosity breaking problem is discussed in U.S. Pat. No. 
4,560,486, which teaches using a partially water soluble tertiary amine in 
conjunction with ammonium persulfates or alkali metal persulfates to break 
the viscosity breaker of fracturing fluids containing polysaccharide 
viscosifiers in formations in the 50.degree. F. to 120.degree. F. 
temperature range. In U.S. Pat. No. 4,552,672, Brown et al. report that 
the minimum practical temperature for peroxygen breakers can be decreased 
from 50.degree. C. to about 20.degree. C. by adding a soluble metal salt 
to accelerate peroxide decomposition, but that peroxide decomposition in 
the presence of metals is difficult to control and reproduce, and that 
adding metals makes the breaking unacceptable, erratic, and 
unreproduceable. 
For the foregoing reasons there is a need for fracturing fluid breakers 
which can effectively break the viscosity of fracturing fluids comprising 
a polysaccharide viscosifier in conjunction with curable resin-coated 
proppants. There is also need for fracturing fluid breakers which 
effectively break the viscosity of fracturing fluids comprising 
polysaccharide viscosifiers in formations at temperature formations in 
problematic 50.degree. F. to 120.degree. F. range. 
SUMMARY 
The present invention is directed to fracturing fluid compositions that 
utilize a new viscosity breaker which functions effectively in the 
presence of uncured resin-coated proppants. Surprisingly, the new 
fracturing fluids also exhibit superior viscosity breaking performance in 
the problematic 50.degree. F. to 120.degree. F. formation temperature 
range both with uncured resin proppants and with other proppants. 
The present invention is directed to polysaccharide viscosified fracturing 
fluids in which a water soluble salt of the periodate or metaperiodate 
radicals is incorporated to break the viscosity of the fracturing fluid. 
The periodate or metaperiodate radical can be added to the fracturing 
fluid in the form of any water soluble salt such as the alkali metal or 
alkaline earth salts. Potassium periodate is particularly favored because 
it can be purchased in an industrial grade and in bulk quantities at 
reasonable price. The present invention also encompasses the fracturing 
processes which apply polysaccharide viscosified fracturing fluids 
containing periodate or metaperiodate breakers. 
These and other features, aspects and advantages of the present invention 
will become better understood with reference to the following description 
and appended claims. 
DETAILED DESCRIPTION AND PREFERRED EMBODIMENTS 
Without intending to be limited by a specific theory, it is hypothesized 
that uncured resin coating on proppants release phenolic derivatives and 
residues which are free radical traps which consume the free radicals 
emitted by peroxy breakers, thus interfering with the free radical 
viscosifier polymer breaking reactions. Accordingly, it would be desirable 
to provide a fracturing fluid viscosity breaker which does not operate via 
the free radical mechanism when resin-coated proppants are to be used. 
It has now been discovered that the salts of periodate and metaperiodate 
radicals are effective viscosity breakers in fracturing fluids comprising 
polysaccharides in conjunction with uncured resin-coated proppants. 
Surprisingly, it has also been discovered that the soluble salts as of 
periodate and metaperiodate radicals are effective viscosity breakers in 
formations which have temperatures in the problematic 50.degree. F. to 
120.degree. F. range, both in conjunction with uncured resin-coated 
proppants and with other types of proppants. 
Suitable periodate and metaperiodate salts include the alkali and alkaline 
earth salts. Potassium periodate, KIO.sub.4, is a preferred agent. 
Periodates and metaperiodates break the polysaccharided chains via an 
oxidation mechanism, not a free radical mechanism. Periodates form 
periodate esters of the 1,2 diol bonds in the polysaccharide which 
disproportionates to form the dialdehyde and iodate anion.

To further illustrate the invention and how the invention may be applied, 
the following Examples are provided. 
EXAMPLE 1 
Break Times in Low Temperature Borate Crosslinked Guar Fluids 
The static break test procedure was used to determine the time required to 
break a borate crosslinked guar fluid that is suitable for use at lower 
formation temperatures using potassium periodate as the breaker. The fluid 
used was guar (0.48%) crosslinked with "POLYBOR" crosslinker. ("POLYBOR" 
is a borate crosslinker sold by U.S. Borax Co.) The pH of the fluid was 
adjusted to pH 9.5 with acetic acid and caustic to facilitate 
crosslinking. 
Tests were conducted at temperatures of 80.degree. F., 100.degree. F. and 
120.degree. F. and at potassium periodate loadings ranging between 0.25 
and 7.0 lb./Mgal. The static break tests were conducted by adding 
potassium periodate to the fluid, then heating the fluid in a water bath 
at the temperature indicated in Table 1. The viscosity of the fluid was 
monitored using a viscometer such as a "BAROID MODEL 35 A FANN" 
viscometer. The break time is defined as the elapsed time for the fluid 
viscosity to decrease below 10 cP at 511 s.sup.-1. 
TABLE 1 
______________________________________ 
Test Temperature 
KIO.sub.4 
Break Time 
Entry 0.degree. F. lb/Mgal hours 
______________________________________ 
1 80 2 24 
2 80 5 8 
3 80 7 6 
4 100 0.5 17 
5 100 1 &lt;17 
6 100 3 3 
7 100 5 2 
8 120 0.25 24 
9 120 0.5 6 
10 120 0.75 2 
11 120 1 2 
______________________________________ 
The results demonstrate that potassium periodate breaks fracturing fluids 
below 120.degree. F. without the need of an activator. The break time of 
the fluid can be varied By controlling the concentration of potassium 
periodate. 
The experiments of Examples 2 to 5 which follow were conducted using five 
commercial curable resin-coated proppants (RCP's) coded as follows: RCP 
"A" is "ACFRAC CR"; RCP "B" is "ACFRAC ULTRA"; RCP "C" IS "SUPER HS"; RCP 
"D" is "STRATAFLEX"; and RCP "E" is "SANTRO SUPER HS". 
EXAMPLE 2 
Effect of Type of Curable Resin-Coated Proppant on Fluid Break Time Using 
Potassium Periodate 
Static break tests were conducted to determine if potassium periodate was 
generally effective in the presence of RCP's. The tests were conducted at 
150.degree. F. and the resin-coated proppant was slurried in the fluid at 
a concentration of 50% by weight. The potassium periodate concentration 
was 0.012% by weight in each test. The fluid designated "GUAR-BO.sub.4 " 
in Table 2 was a guar (0.48 wt. %) gel crosslinked with "POLYBOR" 
crosslinker. The pH of the fluid was adjusted to pH 10 with acetic acid 
and caustic to facilitate crosslinking. The fluid designated 
"CMHPG-Zr(IV)" in Table 2 was a carboxymethyl-hydroxypropyl-guar (0.48 wt. 
%) gel crosslinked with zirconium(IV) lactate crosslinker. The pH of the 
fluid was adjusted to pH 6.5 with acetic acid.. 
TABLE 2 
______________________________________ 
Resin-Coated 
Break Time 
Entry Fluid Type Proppant hours 
______________________________________ 
1 Guar-BO.sub.4 .sup.- 
none 1 
2 Guar-BO.sub.4 .sup.- 
A 1.5 
3 Guar-BO.sub.4 .sup.- 
B 1 
4 Guar-BO.sub.4 .sup.- 
C 1 
5 Guar-BO.sub.4 .sup.- 
D 1 
6 CMHPG-Zr(IV) none 7 
7 CMHPG-Zr(IV) A 7 
8 CMHPG-Zr(IV) B 7 
9 CMHPG-Zr(IV) C 7-24 
10 CMHPG-Zr(IV) D 4 
______________________________________ 
The results demonstrate that potassium periodate is an effective breaker 
for commercial curable resin-coated proppants. 
EXAMPLE 3 
Break Times Vs. Potassium Periodate Loadings With Combinations of Different 
Fluids, Resin-Coated Proppants and Temperatures 
Static break tests were performed to determine potassium periodate loadings 
required to break fluids for a number of combinations of different fluid 
compositions, types of resin-coated proppants, fluid types, temperatures, 
and static break. The tests were conducted were conducted at 150.degree. 
F. or 175.degree. F. and the resin-coated proppant was slurried in the 
fluid at concentrations of 38%, 50%, or 55% by weight. 
The fluid designated Guar-BO.sub.4 - in Table 3 was a guar (0.48%) gel 
crosslinked with POLYBOR. The pH of the fluid was adjusted to pH 10 with 
acetic acid and caustic to facilitate crosslinking. The fluid designated 
CMHPG-Zr(IV) in Table 3 was a carboxymethyl-hydroxpropyl-guar (0.48%) gel 
crosslinked with zirconium(IV) lactate crosslinker. The pH of the fluid 
was adjusted to pH 6.5 with acetic acid. 
TABLE 3 
______________________________________ 
Break 
Fluid Temp. RCP RCP KIO.sub.4 
Time 
Entry Type .degree.F. 
Type lb/gal 
lb/Mgal 
hours 
______________________________________ 
1 Guar-BO.sub.4 .sup.- 
150 A 5 0.5 2 
2 Guar-BO.sub.4 .sup.- 
150 A 5 0.75 1 
3 Guar-BO.sub.4 .sup.- 
150 A 5 1 1 
4 Guar-BO.sub.4 .sup.- 
150 A 5 1.5 0.5 
5 Guar-BO.sub.4 .sup.- 
150 A 10 0.5 &gt;6 
6 Guar-BO.sub.4 .sup.- 
150 A 10 0.75 2 
7 Guar-BO.sub.4 .sup.- 
150 A 10 1 1 
8 Guar-BO.sub.4 .sup.- 
150 A 10 1.5 1 
9 Guar-BO.sub.4 .sup.- 
175 A 5 0.25 &gt;6 
10 Guar-BO.sub.4 .sup.- 
175 A 5 0.5 4 
11 Guar-BO.sub.4 .sup.- 
175 A 5 0.75 2 
12 Guar-BO.sub.4 .sup.- 
175 A 5 1 5 
13 Guar-BO.sub.4 .sup.- 
150 C 8 0.5 &gt;6 
14 Guar-BO.sub.4 .sup.- 
150 C 8 1 1 
15 Guar-BO.sub.4 .sup.- 
150 C 8 1.5 0.5 
16 CMHPG- 150 A 5 0.5 &gt;8 
Zr(IV) 
17 CMHPG- 150 A 5 1 4 
Zr(IV) 
18 CMHPG- 150 A 5 2 1 
Zr(IV) 
19 CMHPG- 150 A 5 3 0.5 
Zr(IV) 
20 CMHPG- 150 A 10 0.5 &gt;8 
Zr(IV) 
21 CMHPG- 150 A 10 1 4 
Zr(IV) 
22 CMHPG- 150 A 10 2 1 
Zr(IV) 
23 CMHPG- 150 A 10 3 1 
Zr(IV) 
24 CMHPG- 175 A 5 1 &gt;24 
Zr(IV) 
25 CMHPG- 175 A 5 1.5 1 
Zr(IV) 
26 CMHPG- 175 A 5 2 1 
Zr(IV) 
27 CMHPG- 175 A 10 0.5 &gt;24 
Zr(IV) 
28 CMHPG- 175 A 10 1 2 
ZR(IV) 
29 CMHPG- 175 A 10 1.5 1 
Zr(IV) 
30 CMHPG- 175 A 10 2 1 
Zr(IV) 
31 CMHPG- 150 C 8 0.5 &gt;24 
Zr(IV) 
32 CMHPG- 150 C 8 1 4 
Zr(IV) 
33 CMHPG- iso C 8 1.5 2 
Zr(IV) 
34 CMHPG- 150 C 8 2 1 
Zr(IV) 
35 CMHPG- 175 C 8 0.5 24 
Zr(IV) 
36 CMHPG- 175 C 8 1 2 
Zr(IV) 
37 CMHPG- 175 C 8 1.5 1 
Zr(IV) 
______________________________________ 
The results demonstrate that potassium periodate is effective in a wide 
variety of combinations of fluids, temperatures, and RCP types and 
concentrations. Break times can be varied by varying the concentration of 
potassium periodate. 
EXAMPLE 4 
Break Times of Fluids Containing Potassium Periodate and Resin-Coated 
Proppants with Temperature Ramped from 80.degree.-170.degree. F..sup.1 
These tests were conducted as in Example 3 except the bath temperature was 
ramped from 80.degree. F. to 170.degree. F. at a rate of 30.degree. 
F./hour. After reaching 170.degree. F., the bath was kept at this 
temperature. 
TABLE 4 
______________________________________ 
Break 
Fluid RCP KIO.sub.4 
Time 
Entry Type RCP lb/gal 
lb/Mgal 
hours 
______________________________________ 
1 Guar-BO.sub.4 .sup.- 
A 8 0.5 &gt;24 
2 Guar-BO.sub.4 .sup.- 
A 8 1 4 
3 Guar-BO.sub.4 .sup.- 
A 8 2 2 
4 Guar-BO.sub.4 .sup.- 
B 8 0.5 &gt;24 
5 Guar-BO.sub.4 .sup.- 
B 8 1 4 
6 Guar-BO.sub.4 .sup.- 
B 8 2 2 
7 Guar-BO.sub.4 .sup.- 
C 8 0.5 &gt;24 
8 Guar-BO.sub.4 .sup.- 
C 8 1 4 
9 Guar-BO.sub.4 .sup.- 
C 8 2 2 
10 Guar-BO.sub.4 .sup.- 
E 8 0.5 &gt;24 
11 Guar-BO.sub.4 .sup.- 
E 8 1 2 
12 Guar-BO.sub.4 .sup.- 
E 8 2 2 
13 CMHPG-Zr(IV) A 8 0.5 &gt;24 
14 CMHPG-Zr(IV) A 8 1 4 
15 CMHPG-Zr(IV) A 8 2 4 
16 CMHPG-Zr(IV) B 8 0.5 &gt;24 
17 CMHPG-Zr(IV) B 8 1 6 
18 CMHPG-Zr(IV) B 8 2 2 
19 CMHPG-Zr(IV) C 8 0.5 &gt;24 
20 CMHPG-Zr(IV) C 8 1 4 
21 CMHPG-Zr(IV) C 8 2 2 
22 CMHPG-Zr(IV) E 8 0.5 &gt;24 
23 CMHPG-Zr(IV) E 8 1 4 
24 CMHPG-Zr(IV) E 8 2 2 
______________________________________ 
EXAMPLE 5 
Effect of Potassium Periodate on Compressive Strength of Curable 
Resin-Coated Proppants 
To determine the compatibility of the potassium periodate and the curable 
resin-coated proppant, compressive strength tests were conducted with and 
without potassium periodate. In these tests, the resin-coated proppant was 
slurred in a 0.48% CMHPG gel. The concentration of proppant was 65%. The 
resin-coated proppant was allowed to settle, then the excess fluid was 
removed. The proppant was encased in a cell that was pressured to 1000 
psi. The cells were placed in a 200.degree. F. preheated oven for 20 
hours. After cooling to room temperature, the consolidated proppant was 
removed from the cell. The load required to crush the consolidated 
proppant was determined. The compressive strength (psi) was calculated. 
TABLE 5 
______________________________________ 
Compressive 
KIO.sub.4 
Strength 
Entry RCP lb/Mgal psi 
______________________________________ 
1 A 0 1995 
2 A 1 1947 
3 B 0 201 
4 B 1 224 
5 C 0 737 
6 C 1 817 
7 D 0 497 
8 D 1 434 
______________________________________ 
The results of these tests clearly demonstrate that potassium does not 
influence the developed compressive strength of the curable resin-coated 
proppant. 
EXAMPLE 6 
Typical (Prospective) Application of Invention 
About 20,000 gallons of water from a local source is added to a frac tank 
located near the well that is to be hydraulically fractured. About one 
pound of a bactericide, 2,2 dibromonitrilopropionamide, is deposited in 
the frac tank before the water is charged into the frac tank. The water is 
recirculated from the bottom of the tank to the top using a centrifugal 
pump. About 800 lbs. of a CMHPG, a modified guar viscosifier, is added to 
the recirculating water to hydrate the thickener. Then, the pH of the 
fracturing fluid is adjusted to 6.5 by adding acetic acid to the 
recirculating fracturing fluid. 
To commence the fracturing operation, the fracturing fluid is pumped from 
the frac tank to a small mixing tank which is equipped with a rotating 
mixer. The fracturing fluid is pumped from the mixing tank to the suction 
of the high pressure downhole pump using a centrifugal pump. 
Simultaneously, about 10,000 lbs. of the resin-coated proppant is fed into 
the mixing tank at a controlled uniform rate using an auger feeder where 
it is blended into the fracturing fluid. About 80 lbs. of zirconium (IV) 
lactate, the cross-linker, and 20 lbs. of potassium periodate, the 
breaker, are fed uniformly at a controlled rate into the fracturing fluid 
at the suction of the centrifugal transfer pump. The pressure at the 
discharge of the high pressure downhole pump is about 10,000 psi. The 
pressurized fracturing fluid opens cracks in the subterranean formation 
and flows into the fissures. 
When the batch of fracturing fluid has been pumped down the well, the 
downhole pump is shutdown, the well is shut in by closing a valve on the 
downhole pump discharge typically for between about six to twenty hours. 
During the shutin period, fluid pressure in the well falls as the 
fracturing fluid flows into the fissures in the formation. The formation 
cracks close against the proppant but the proppant maintains open pathways 
for flow. By the end of the shutin period, the viscosity breaker has 
functioned to reduce the viscosity of the viscosifier. When the shutin 
valve on the surface is opened, the now thinned fracturing fluid reverses 
flow direction and flows out of the formation cracks back into and up the 
well, leaving the proppant in the fissures. The fracture fluid is 
collected at the surface, treated and disposed. Oils and/or gas production 
proceeds. 
Although the present invention has been described in considerable detail 
with reference to certain preferred versions thereof, other versions are 
possible. Therefore, the scope of the appended claims should not be 
limited to the description of the preferred versions herein.