Wells – Processes – Material placed in pores of formation to treat resident...
Reexamination Certificate
1999-04-23
2001-09-04
Neuder, William (Department: 3672)
Wells
Processes
Material placed in pores of formation to treat resident...
C166S281000, C507S921000
Reexamination Certificate
active
06283212
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Technical Field of the Invention
The present Invention relates to hydrocarbon well stimulation, and more particularly to methods and compositions to remove (and more generally to transfer) fluid deliberately introduced into the subsurface. For instance, the methods and compositions of the present invention involve creating then exploiting a capillary pressure gradient at the fracture face to systematically induce fluid flow from the fracture into the formation (or from the formation into the fracture), thereby increasing effective fracture length, hence, improving conductivity.
This Application is one member of a family of patent applications by Hinkel and England, the Inventors of the present Invention, and assigned to Schlumberger Technology Corporation. The common feature of these Applications is that they are all directed to transferring fluids in the subsurface by non-hydraulic means. The other Applications in this family are, Enhancing Fluid Removal From Subsurface Fractures Deliberately Introduced Into the Subsurface, U.S. patent application Ser. No. 09/087,286; and, Novel Fluids and Techniques for Maximizing Fracture Fluid Clean-up, U.S. patent application Ser. No. 09/216,420. Each of these Applications is incorporated by reference in its entirety into the present Application.
2. The Prior Art
The present Invention relates generally to hydrocarbon (petroleum and natural gas) production from wells drilled in the earth. Obviously, it is desirable to maximize both the rate of flow and the overall capacity of hydrocarbon from the subsurface formation to the surface, where it can be recovered. One set of techniques to do this is referred to as “stimulation” and one such technique, “hydraulic fracturing,” is the primary, though not the exclusive subject of the present Invention.
The rate of flow or “production” of hydrocarbon from a geologic formation is naturally dependent on numerous factors. One of these factors is the radius of the borehole; as the bore radius increases, the production rate increases, everything else being equal. Another, related to the first, is the flowpaths available to the migrating hydrocarbon.
Drilling a hole in the subsurface is expensive—which limits the number of wells that can be economically drilled—and this expense only generally increases as the size of the hole increases. Additionally, a larger hole creates greater instability to the geologic formation, thus increasing the chances that the formation will shift around the wellbore and therefore damage the wellbore (and at worse collapse). So, while a larger borehole will, in theory, increase hydrocarbon production, it is impractical, and there is a significant downside. Yet, a fracture or large crack within the producing zone of the geologic formation, originating from and radiating out from the wellbore, can actually increase the “effective” (as opposed to “actual”) wellbore radius, thus, the well behaves (in terms of production rate) as if the entire wellbore radius were much larger. Hence, the hydrocarbon can move from the formation into and along or within the fracture and more easily to the wellbore.
Fracturing (generally speaking, there are two types, acid fracturing and propped fracturing, the latter of primary interest here) thus refers to methods used to stimulate the production of fluids resident in the subsurface, e.g., oil, natural gas, and brines. Hydraulic fracturing involves literally breaking or fracturing a portion of the surrounding strata, by injecting a specialized fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation (i.e. above the minimum insitu rock stress). Morc particularly, a fluid is injected through a wellbore; the fluid exits through holes (perforations in the well casing) and is directed against the face of the formation (sometimes wells are completed openhole where no casing and therefore no perforations exist so the fluid is injected through the wellbore and directly to the formation face) at a pressure and flow rate sufficient to overcome the minimum insitu stress (also known as minimum principal stress) to initiate and/or extend a fracture(s) into the formation. Actually, what is created by this process is not always a single fracture, but a fracture zone, i.e., a zone having multiple fractures, or cracks in the formation, through which hydrocarbon can more easily flow to the wellbore.
In practice, fracturing a well is a highly complex operation performed with precise and exquisite orchestration of equipment, highly skilled engineers and technicians, and powerful integrated computers that monitor rates, pressures, volumes, etc. in real time. During a typical fracturing job, tens of thousands of gallons of materials are pumped into the formation at pressures high enough to actually split the formation in two, thousands of feet below the earth's surface.
A typical fracture zone is shown in context, in FIG.
1
. The actual wellbore—or hole in the earth into which pipe is placed through which the hydrocarbon flows up from the hydrocarbon-bearing formation to the surface—is shown at
10
, and the entire fracture zone is shown at
20
. The vertical extent of the hydrocarbon-producing zone is ideally (but not generally) coextensive with the fracture-zone height (by design). These two coextensive zones are shown bounded by
22
and
24
. The fracture is usually created in the producing zone of interest (rather than another geologic zone) because holes or perforations,
26
-
36
, are deliberately created in the well casing beforehand; thus the fracturing fluid flows down (vertically) the wellbore and exits through the perforations. Again, the reservoir does not necessarily represent a singular zone in the subterranean formation, but may, rather represent multiple zones of varying dimensions.
Thus, once the well has been drilled, fractures are often deliberately introduced in the formation, as a means of stimulating production, by increasing the effective wellbore radius. Clearly then, the longer the fracture, the greater the effective wellbore radius. More precisely, wells that have been hydraulically fractured exhibit both radial flow around the wellbore (conventional) and linear flow from the hydrocarbon-bearing formation to the fracture, and further linear flow along the fracture to the wellbore. Therefore, hydraulic fracturing is a common means to stimulate hydrocarbon production in low permeability formations. In addition, fracturing has also been used to stimulate production in high permeability formations. Obviously, if fracturing is desirable in a particular instance, then it is also desirable, generally speaking, to create as large (i.e., long) a fracture zone as possible—e.g., a larger fracture means an enlarged flowpath from the hydrocarbon migrating towards the wellbore and to the surface.
Yet many wells behave as though the fracture length were much shorter because the fracture is contaminated with fracturing fluid (i.e., more particularly, the fluid used to deliver the proppant as well as a fluid used to create the fracture, both of which shall be discussed below). The most difficult portion of the fluid to recover is that retained in the fracture tip—i.e. the distant-most portion of the fracture from the wellbore. Thus, the result of stagnant fracturing fluid in the fracture naturally diminishes the recovery of hydrocarbons. The reasons for this are both simple and complex. Most simply, the presence of fluid in the fracture acts as a barrier to the migration of hydrocarbon from the formation into the fracture. More precisely, the aqueous-based fluid saturates the pore spaces of the fracture face, preventing the migration of hydrocarbon into the same pore spaces, i.e., that fluid-saturated zone has zero permeability to hydrocarbon.
Indeed, diminished effective fracture length caused by stagnant fluid retained in the fracture tip is perhaps the most significant variables limiting hydrocarbon production (both rate and capacity)
England Kevin W.
Hinkel Jerald J.
Hawkins Jennifer M
Mitchell Thomas O.
Nava Robin C.
Neuder William
Schlumberger Technology Corporation
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