Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
1999-08-26
2002-08-13
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S922000, C507S203000, C507S240000, C507S261000, C507S265000, C507S266000, C166S308400, C516S056000, C516S024000
Reexamination Certificate
active
06432885
ABSTRACT:
FIELD OF THE INVENTION
This invention relates to well treatment fluids comprising amphoteric surfactants and methods of using those fluids to treat and/or fracture subterranean formations.
BACKGROUND OF THE INVENTION
Hydraulic fracturing is used by the petroleum industry to increase well productivity or injectivity by creating highly conductive paths some distance from the well bore in a formation. The fracturing is created by injecting suitable fluids into the well under pressure until the reservoir rock fractures.
Water soluble polymers have been extensively used in the petroleum industry to enhance the productivity of oil and gas operations. These polymers have been used in drilling fluids, gravel pack fluids, fluid loss circulation, and hydraulic fracturing. These i. techniques have one priority in common and that is the ability of the water soluble polymer to suspend solids. Common water soluble polymers used are hydroxy ethyl cellulose (HEC), xanthan gum, crosslinked guar and its derivatives. HEC is typically used for low temperature applications due to its high decrease in viscosity with increase in temperature. Xanthan gum has superior suspension properties over HEC especially at higher temperatures, but because of its higher molecular weight, xanthan gum tends to filter out at the formation face at low permeabilities (less than 50 md (5×10
−8
m
2
)). This is adequate for drill-in fluids since acid and/or oxidizers are subsequently used to remove most of the polymer damage. Xanthan gum is not typically used for hydraulic fracturing because of the difficulty in placing the acid over the proppant if filtered out. If the permeability is high enough for the xanthan gum to flow through the formation, the polymer has a tendency to impart formation damage. Therefore, crosslinked guar and its derivatives have been developed that minimize formation invasion by incorporating a filter cake. Breakers are typically added to the fluid so that they react within the filter cake to allow ease of the oil and gas during flowback. However, the filter cake is typically broken in fragments and is entrained by the proppant, thereby reducing well conductivity.
U.S. Pat. No. 3,960,736 discloses an acid type breaker for lowering the viscosities of polysaccharide solutions using organic esters. In the examples, the pH needs to be lowered to about 3 using an ester to reduce viscosity by 50% within 4 hours from the solution without an ester. If the pH is about 5 to 6, then a longer time of about 24-72 hours are required. In acid soluble formations containing limestone this breaking time cannot be predicted since acid hydrolyzed ester can react with the limestone instead of the polysaccharide.
U.S. Pat. No. 5,551,516 discloses cationic surfactants based upon quaternary ammonium halide salts. The compositions appear to have stable fluid viscosities of about 225° F. (107° C.) and are disclosed to be useful in fracturing. However they fail to address the problems that can occur, like formation damage and ease of flowback by reducing the viscosity after fracture is completed.
WO 99/24693 discloses viscoelastic surfactant fracturing fluids comprising an aqueous medium, an inorganic water soluble salt, a surfactant (anionic, non-ionic or hydrotropic), and optional organic alcohols. Although not mentioned in the disclosures, WO 99/24693's examples produce acidic solutions having a pH less than 2.0. Flowing these types of fluids through Berea sandstone cores produces extreme formation damage (more than 90% damage). The acidic viscous solution reacts with acid soluble materials within the core. Once dissolved the acid insoluble materials are released. Then the viscous solution carries these materials within the core and plugs the pore throats. These problems render WO 99/24693's compositions commercially non-viable.
The inventor herein has discovered that WO 99/24693's acidic solutions can be made neutral or basic without substantially affecting its viscosity. Although this imparts less formation damage, removing the viscous solution is difficult and requires days or weeks of flushing to obtain 20% damage. Further the inventor herein has discovered that providing a breaker to substantially lower the viscosity of the fluid once the fracturing is completed can prevent the proppant from flowing back to surface once the well is put on production. This prevents damage to equipment, lines, and values due to the abrasiveness of the proppant.
The present invention provides fluid stable compositions having stable viscosities above 300° F. (149° C.) that are also pH sensitive so that the fluids may be easily treated to reduce the viscosity and obtain easier flowback and less formation damage.
SUMMARY OF THE INVENTION
This invention relates to well treatment fluids comprising amphoteric surfactant(s), water, non-aqueous solvent(s) and optionally an acid forming compound (provided that if the acid forming compound is present a hydrophilic alcohol may also be optionally present.) and methods of using those fluids to treat or fracture subterranean formations.
DETAILED DESCRIPTION OF THE INVENTION
This invention relates to well treatment fluids comprising:
(a) one or more amphoteric surfactants, preferably present at about 1 to about 50 weight percent, more preferably 1 to 40 weight percent, more preferably about 2 to about 30 weight percent, even more preferably at about 5 to about 25 weight percent based upon the weight of the fluid;
(b) water, preferably present at about 30 to about 95 weight percent, more preferably about 40 to about 90 weight percent, even more preferably at about 50 to about 85 weight percent, based upon the weight of the fluid;
(c) non-aqueous solvent(s), preferably present at about 0.1 to about 25 weight percent, more preferably about 0.5 to about 20 weight percent, even more preferably at about 1 to about 15 weight percent, based upon the weight of the fluid; and
(d) optionally, an acid forming compound preferably present at about 0.005 to about 10 weight percent, more preferably about 0.01 to about 5 weight percent, even more preferably at about 0.05 to about 2 weight percent, based upon the weight of the fluid, provided that when the acid forming compound is present a hydrophilic alcohol (i.e. preferably an alcohol that retards the hydrolysis reaction of the acid forming compound) may also be present at about 0.1 to about 15 weight percent, more preferably about 0.5 to about 12 weight percent, even more preferably at about 1 to about 8 weight percent, based upon the weight of the fluid.
In a preferred embodiment the amphoteric surfactant is present at about 8 weight percent to about 10 weight percent and the solvent is present at about 5 weight percent to about 7 weight percent.
In a preferred embodiment the water may be freshwater or salt water. In another embodiment the water may be seawater or water that has had a salt added to it. Such salts include potassium chloride, sodium chloride, cesium chloride, ammonium chloride, calcium chloride, magnesium chloride, sodium bromide, potassium bromide, cesium bromide, calcium bromide, zinc bromide, sodium formate, potassium formate, cesium formate, sodium acetate and mixtures thereof. In one embodiment the salt is present at up to 4 weight % and the salt water is used to treat the formation prior to introducing the fluid into the formation.
In another embodiment the pH of the fluid is, or is adjusted to, about 6.5 or more, more preferably 7 or more, more preferably 8 or more, more preferably 9 or more, more preferably between 9 and 15, more preferably between 7.5 and 9.5. The pH may be adjusted by any means known in the art, including adding acid or base to the fluid, bubbling CO
2
through the fluid and the like.
In another embodiment the fluid further comprises a hydrophobic organic alcohol, preferably a C
4
to C
20
hydrophobic alcohol, preferably C
4
to C
20
linear alcohols, preferably an alcohol selected from the group consisting of diethanol, propanol, butanol, pentanol, heptanol, nonanol, decanol, dodecanol, phe
Osca, Inc.
Tucker Philip
LandOfFree
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