Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
2001-05-08
2003-08-12
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S209000, C507S212000, C507S216000, C507S240000, C507S265000, C507S271000, C507S273000, C507S225000, C507S903000, C507S922000, C166S308400, C166S278000
Reexamination Certificate
active
06605570
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates to wellbore services, especially the drilling, completion or stimulation of hydrocarbon wells, and in particular to fluids and methods for drilling or drill-in with minimal fluid loss to the overburden or productive pay, hydraulic fracturing of a subterranean formation with minimal loss of fluid to the formation during fracturing, or to gravel packing a subterranean formation with minimal loss of fluid to the formation during gravel packing.
2. Description of Related Art
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be produced there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock, which has pores of sufficient size, connectivity, and number to provide a conduit for the hydrocarbon to move through the formation.
One reason why low production sometimes occurs is that the formation is naturally “tight” (low permeability), that is, the pore throats are so small that the hydrocarbon migrates toward the wellbore only very slowly. Alternatively, or in combination, the formation or wellbore may be “damaged” by, e.g., dehydration of drilling or drill-in fluid; the presence of certain types of hydrocarbon, i.e. waxes and asphaltenes; and the occurrence of inorganic scale. The common denominator in both cases (damage and tight formations) is low permeability.
Techniques performed by hydrocarbon producers to increase the net permeability of the formation are referred to as “stimulation.” Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore and/or into the formation to react with and dissolve the damage; (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating hydrocarbon around or through the damage); (3) injecting chemicals into the wellbore that will contact drilling or drill-in fluid filter cake that resides along the face of the wellbore thus removing filter cake from the wellbore face; or (4) injecting chemicals through the wellbore and into the formation at pressures sufficient to fracture the formation (“hydraulic fracturing”), thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. With respect to stimulation, the present invention is directed primarily to the fourth of these processes, but applies to all four processes in instances where a need to control the rate of treatment fluid lost into the formation is beneficial.
Hydraulic fracturing involves breaking or fracturing a portion of the surrounding strata, by injecting a fluid into a formation through the wellbore, and through perforations if the well has been cased, at a pressure and flow rate sufficient to overcome the minimum in situ stress (also known as minimum principal stress) to initiate or extend a fracture(s) into the formation.
This process typically creates a fracture zone having one or more fractures in the formation through which hydrocarbons can more easily flow to the wellbore.
Since the main functions of a fracturing fluid are to initiate and propagate fractures and to transport a proppant (usually sand, glass or ceramic beads used to hold the walls of the fracture apart after the pumping has stopped and the fracturing fluid has leaked off or flowed back) the viscous properties of the fluids are most important. Many known fracturing fluids comprise a water-based carrier fluid, a viscosifying agent, and the proppant. The viscosifying agent is often a cross-linked water-soluble polymer. As the polymer undergoes hydration and crosslinking, the viscosity of the fluid increases and allows the fluid to initiate the fracture and to carry the proppant. Another class of viscosifying agent is viscoelastic surfactants (“VES's”).
Both classes of fracturing fluids (water with polymer, and water with VES) can be pumped as foams or as neat fluids (i.e. fluids having no gas dispersed in the liquid phase). Foamed fracturing fluids typically contain nitrogen, carbon dioxide, or mixtures thereof at volume fractions ranging from 10% to 90% of the total fracturing fluid volume. The term “fracturing fluid,” as used herein, refers to both foamed fluids and neat fluids.
VES-based fracturing fluids, like other fracturing fluids, may leak-off from the fracture into the formation during and after the fracturing process. The VES leak-off is viscosity controlled, and the leak-off rate depends on several factors, including formation permeability, formation fluids, applied pressure drop, and the rheological properties of the VES fluids. Leak-off is particularly problematic in medium to high permeability formations (greater than about 2 mD, especially greater than about 10 mD, most especially greater than about 20 mD). The rate at which fluid leaks off from the fracture generally increases with increasing rock permeability and with increasing net positive pressure differential between the fluid in the fracture and the pore pressure of fluid in the formation. Fluid loss is a term often used for the flow of fracturing fluid into the formation from the fracture. (The terms “fluid loss” and “leak-off” are used interchangeably herein.) Fluid loss control is a term often used to indicate measures used to govern the rate and extent of fluid loss. The consequence of high fluid loss (also referred to as low fluid efficiency, where fluid efficiency is inversely proportional to the fluid loss into the formation) is that it is necessary to inject larger volumes of a fracturing fluid in order to create the designed fracture geometry, i.e., fracture length and width sufficient to hold all the injected proppant. Use of low efficiency fluids can increase the time and expense required to perform the fracturing operation. U.S. Pat. No. 5,964,295, which is hereby incorporated by reference, describes VES fluids developed in particular for use in low permeability formations and indicates that VES fluids are not normally used in high permeability applications unless the size of the job and the volume of fluids needed are small.
Viscosified fluids are also used in other wellbore services, such as sand control, drilling and completion. Gravel packing and “drill-in” (which is drilling in the productive formation) with special fluids are two techniques that are commonly used to minimize damage to the producing zone during the completion process.
Sand control is the term used to describe the prevention or minimization of the migration of fine, mobile particles during hydrocarbon production. In this connection, “sand” is used to describe any such particles and the formation need not be a sand or sandstone. Sand control can involve an operation where a device is first placed into the wellbore across the producing interval that serves to filter fine, mobile formation particles from the produced oil, water, or gas. This device is often called a sand control screen. Frequently, a graded material (such as 20/40 mesh sand) is placed such that it completely occupies the annular space between the exterior of the screen and the sand face. This “gravel pack” is designed to further filter mobile particles from the produced oil, water, or gas so that those particles do not cause screen blocking or erosion. The gravel is placed in this annular gap by pumping a slurry which is typically an aqueous fluid containing the gravel. This slurry is injected from the surface and is diverted into the annulus once the fluid reaches the depth of the screen. The carrier fluid often contains materials to viscosify it and enhance the performance of the slurry. The viscosifying materials may include polymers (such as guar or hyd
Miller Matthew J.
Olsen Thomas N.
Samuel Mathew
Vinod Palathinkara S.
Jeffery Brigitte
Menes Catherine
Mitchell Thomas O.
Schlumberger Technology Corporation
Tucker Philip
LandOfFree
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