Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
2001-02-15
2003-11-18
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S211000, C507S240000, C507S271000, C507S903000, C507S922000, C166S308400
Reexamination Certificate
active
06649572
ABSTRACT:
FEDERALLY SPONSORED RESEARCH
Not applicable.
REFERENCE TO MICROFICHE APPENDIX
Not applicable.
BACKGROUND OF THE INVENTION
Production of oil and gas from subterranean formations is dependent on many factors. These hydrocarbons must usually migrate through a low permeable formation matrix to drain into the wellbore. In many formations, the permeability is so low that it hinders the well's production rate and overall potential. In other wells, the near wellbore is damaged during drilling operations and such damage often results in less than desirable well productivity. Hydraulic fracturing is a process designed to enhance the productivity of oil and gas wells or to improve the injectivity of injection wells.
In the fracturing process, a viscous fluid is injected into the wellbore at such a rate and pressure as to induce a crack or fracture in the formation. Once the fracture is initiated, a propping agent, such as sand, is added to the fluid just prior to entering the wellbore. This sand laden slurry is continuously injected causing the fracture to propagate or extend. After the desired amount of proppant has been placed in the reservoir, pumping is terminated, and the well is shut-in for some period of time. Later, the well is opened, initially to recover a portion of the treating fluid and later the hydrocarbons. The hydraulic fracturing process is successful because the hydrocarbons are now able to drain into the propped fracture that serves as a highly conductive channel leading directly to the wellbore.
The fracturing treatment is dependent, in part, on the properties of the fracturing fluid. The fluid must attain high viscosities, minimize solvent loss to the formation matrix (known in the art as fluid loss control) and adequately suspend the proppant. The fracturing fluid is prepared by first dissolving polymers in a solvent. Generally, the solvent is water which is often made saline or contains other additives to minimize clay expansion and migration in the formation matrix. The fracturing fluids are typically composed of water soluble polymers, crosslinking agents, breakers and other additives, such as surfactants, which are employed to prevent well specific problems such as water blocks or emulsions.
The water soluble polymers most often used are either guar gum or a guar gum derivative. The derivatives usually are hydroxypropyl guar (HPG), carboxymethyl guar (CMG) or carboxymethylhydroxypropyl guar (CMHPG). Less often, cellulose derivatives such as hydroxyethyl cellulose (HEC) or carboxymethylhydroxypropyl cellulose are used, but are generally cost prohibitive. Lastly, biopolymers such as xanthan gum have been used in rare occasions. At polymer concentrations usually ranging from 0.24 to 0.72 weight percent, the viscosities of the solutions made from these polymers are too low in most instances to be used as a fracturing fluid. As a reference, a 0.48 weight percent polymer solution (i.e. without a crosslinking agent) generally provides a viscosity of less than 50 centipoise (cps) at 511 s
−1
. The viscosity of polymer solutions may be enhanced by the addition of a crosslinking agent. Typical crosslinking agents contain titanium, zirconium or boron ions. These agents work by binding the polymer chains together. Since the viscosity is derived exponentially from the polymer's molecular size, binding the polymers together dramatically increases their size and consequently, the viscosity.
Traditionally, polymer concentration has been viewed as the important factor in obtaining fracturing fluid stability, i.e. maintenance of viscosity at an acceptable level, at a prescribed temperature, for a defined period of time. The convention in the art has been to increase polymer concentration or loading to increase stability for long pumping times or for treating formations at high temperatures. For example, in wells having high temperatures in excess of about 350° F. (177° C.), the polymer loading may exceed 0.72 weight percent. At the other extreme, a useful fracturing fluid could not be obtained at polymer concentrations of less than 20 pounds per thousand gallons (ppt), or 0.24 weight percent. In practice, an increase in viscosity above the polymer solution is not obtained and many times the polymer may precipitate from solution when crosslinker is added. However, it would be highly desirable to have stable, crosslinked fracturing fluids using polymer loadings of 20 ppt less.
SUMMARY OF THE INVENTION
The surprising discovery has been made that crosslinked fracturing fluids having substantially reduced polymer loadings can be made that have performance equivalent to conventional crosslinked fracturing fluids. The fluids of the present invention include modified polymers having randomly distributed anionic substituents which yield high viscosity. The modified polymers may be crosslinked with suitable crosslinking agents to form viscous gels that are stable at polymer concentrations as low as 0.12 weight percent. The fluids of this invention provide many advantages in that equivalent fracturing fluid performance may be obtained at reduced overall treatment costs. Reduced polymer loadings may also result in less damage to the fracture sand pack and the surrounding subterranean formation after the fracturing treatment.
BRIEF DESCRIPTION OF THE DRAWINGS
Not applicable.
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
The invention described below is a modified hydraulic fracturing fluid and method of its use to stimulate oil and gas wells. Fracturing fluids are conventionally made of water soluble polymers which are crosslinked in order to produce sufficient viscosity to create a fracture and to place a propping agent into the created fracture. To serve these functions properly, it is believed in the art that the fluid must maintain a critical minimum viscosity. Fracturing fluid systems have been developed so that the critical minimum viscosity is maintained for various time periods at various temperatures. Generally, fluids with viscosity values exceeding 100 cps at 105 sec
−1
are thought to be adequate for fracturing wells. It is desirable for all of the fracturing fluid to be pumped into the formation before the viscosity of the initially pumped fluid reaches that minimum. To obtain such performance, fracturing fluid systems normally contain polymer concentrations greater than the C* concentration for the polymer.
The C* concentration is described as that concentration necessary to cause polymer chain overlap. Suitable polymer chain overlap to effectively obtain a crosslinked gel is thought to occur when polymer concentration exceeds the C* concentration. In fact, the higher the polymer concentration, the greater the polymer chain overlap and the greater the gel strength after crosslinking. The literature often recites the C* concentration for guar to be about 0.19 to 0.22 weight percent polymer. Consequently, the lowest concentration of polymer typically used in hydraulic fracturing applications to form crosslinked gels has been about 0.24 weight percent or 20 pounds per thousand gallons (ppt). However, such gels typically have very limited stability at the temperatures frequently encountered in fracturing applications.
CMG and CMHPG contain carboxylate groups which are anionically charged except in strong acid. These anionically charged groups tend to repel away from one another. Because they are chemically bound to the polymer, repulsion of the anionic groups also causes the polymer to occupy a much larger volume than the unsubstituted guar polymer. Surprisingly, it has been found that some carboxylated guar derivatives have C* values as low as 0.06 weight percent. These polymers were found to make suitable crosslinked gels that were applicable for hydraulic fracturing processes at concentrations as low as 0.12 weight percent or 10 ppt. Although previously such fluids were not stable at temperatures higher than ambient, it has surprisingly been discovered that polymer loadings of about 0.14 weight percent are stable up to 150° F. (65° C.) and useful gels with s
Dawson Jeffrey C.
Kesavan Subramanian
Le Hoang Van
B J Services Company
Brinks Hofer Gilson & Lione
Tucker Philip
LandOfFree
Polymer expansion for oil and gas recovery does not yet have a rating. At this time, there are no reviews or comments for this patent.
If you have personal experience with Polymer expansion for oil and gas recovery, we encourage you to share that experience with our LandOfFree.com community. Your opinion is very important and Polymer expansion for oil and gas recovery will most certainly appreciate the feedback.
Profile ID: LFUS-PAI-O-3129849