Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
1999-10-15
2002-06-04
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S131000, C507S135000, C507S138000, C507S145000, C507S244000, C507S259000, C507S265000, C507S267000, C507S269000, C507S933000
Reexamination Certificate
active
06399546
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Technical Field of the Invention
This Invention relates to a novel reversible thickener, i.e., a fluid whose viscosity can be carefully modulated—from very low viscosity to sufficient viscosity to act as a barrier to further flow; particularly preferred embodiments are directed to fluids and methods for stimulating hydrocarbon-bearing formations—i.e., to increase the production of oil/gas from the formation. In particular, the Present Invention is directed to a family of fluids (and methods incorporating those fluids) intended to be pumped through a wellbore and into the hydrocarbon-bearing formation.
2. Introduction to the Technology
For ease of understanding, the novel fluid systems of the Present Invention will be described with respect to their preferred commercial applications. Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the oil to reach the surface. In order for oil to be “produced,” that is, travel from the formation to the wellbore (and ultimately to the surface) there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock—e.g., sandstone, carbonates—which has pores of sufficient size and number to allow a conduit for the oil to move through the formation.
One of the most common reasons for a decline in oil production is “damage” to the formation that plugs the rock pores and therefore impedes the flow of oil. Sources of formation damage include: spent drilling fluid, fines migration, paraffin, mineral precipitation (scale). This damage generally arises from another fluid deliberately injected into the wellbore, for instance, drilling fluid. Even after drilling, some drilling fluid remains in the region of the formation near the wellbore, which may dehydrate and form a coating on the wellbore. The natural effect of this coating is to decrease permeability to oil moving from the formation in the direction of the wellbore.
Another reason for lower-than-expected production is that the formation is naturally “tight,” (low permeability formations) that is, the pores are sufficiently small that the oil migrates toward the wellbore only very slowly. The common denominator in both cases (damage and naturally tight reservoirs) is low permeability. Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir are referred to as “stimulation techniques.” Essentially, one can perform a stimulation technique by: (1) injecting chemicals into the wellbore to react with and dissolve the damage (e.g., wellbore coating); (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 oil around the damage); or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbon can more readily move from the formation and into the wellbore. The Present Invention is directed primarily to the latter two of these three processes.
Thus, the Present Invention relates to methods to enhance the productivity of hydrocarbon wells (e.g., oil wells) by removing (by dissolution) near-wellbore formation damage or by creating alternate flowpaths by dissolving small portions of the formation—by techniques known as “matrix acidizing,” and “acid fracturing.” Generally speaking, acids, or acid-based fluids, are useful in this regard due to their ability to dissolve both formation minerals (e.g., calcium carbonate) and contaminants (e.g., drilling fluid coating the wellbore or that has penetrated the formation) which were introduced into the wellbore/formation during drilling or remedial operations.
At present, matrix acidizing treatments are plagued primarily by three very serious limitations: (1) radial penetration; (2) axial distribution; and (3) corrosion of the pumping and well bore tubing. The Present Invention is directed primarily to the first two, and to the largest extent, the second.
The first problem, radial penetration, is caused by the fact that as soon as the acid is introduced into the formation (or wellbore) it reacts very quickly with the wellbore coating, or formation matrix (e.g., sandstone or carbonate). In the case of treatments within the formation (rather than wellbore treatments) the formation near the wellbore that first contacts the acid is adequately treated, though portions of the formation more distal to the wellbore (as one moves radially, outward from the wellbore) remain untouched by the acid—since all of the acid reacts before it can get there. For instance, sandstone formations are often treated with a mixture of hydrofluoric and hydrochloric acids at very low injections rates (to avoid fracturing the formation). This acid mixture is often selected because it will dissolve clays (found in drilling mud) as well as the primary constituents of naturally occurring sandstones (e.g., silica, feldspar, and calcareous material). In fact, the dissolution is so rapid that the injected acid is essentially spent by the time it reaches a few inches beyond the wellbore. Thus, one can calculate that over 100 gallons of acid per foot is required to fill a region five feet from the wellbore (assuming 20% porosity and 6-inch wellbore diameter). Yet, the high rate of acid spending would confine the dissolution of minerals to at most, a distance of one foot away from the wellbore, if a conventional fluid (HCl, or a mixture of HCl and HF) were used. Similarly, in carbonate systems, the preferred acid is hydrochloric acid, whiSch again, reacts so quickly with the limestone and dolomite rock, that acid penetration is limited to from a few inches to a few feet. In fact, due to such limited penetration, it is believed matrix treatments are limited to bypassing near-wellbore flow restrictions—i.e., they do not provide significant stimulation beyond what is achieved through (near-wellbore) damage removal. Yet damage at any point along the hydrocarbon flowpath can impede flow (hence production). Id. Therefore, because of the prodigious fluid volumes required, these treatments are severely limited by their cost.
A second major problem that severely limits the effectiveness of matrix acidizing technology, is axial distribution. This problem relates to the proper placement of the acid-containing fluid—i.e., ensuring that it is delivered to the desired zone (i.e., the zone that needs stimulation) rather than another zone. (Hence this problem is not related per se to the effectiveness of the acid-containing fluid.) More particularly, when an oil-containing formation (which is quite often, though not always, comprised of calcium carbonate) is injected with acid (e.g., hydrochloric acid, or HCl) the acid begins to dissolve the carbonate; as one continues to pump the acid into the formation, a dominant channel through the matrix is inevitably created. And as one continues to pump acid into the formation, the acid will naturally flow along that newly created channel—i.e., the path of least resistance—and therefore leaving the rest of the formation untreated. This of course is undesirable. It is exacerbated by intrinsic heterogeneity with respect to permeability (common in many formations)—this occurs to the greatest extent in natural fractures in the formation and due to high permeability streaks. Again, these regions of heterogeneity in essence attract large amounts of the injected acid, hence keeping the acid from reaching other parts of the formation along the wellbore—where it is actually desired most. Thus, in many cases, a substantial fraction of the productive, oil-bearing intervals within the zone to be treated are not contacted by acid sufficient to penetrate deep enough (laterally in the case of a
Chang Frank F.
Miller Matthew J.
Qu Qi
Mitchell Thomas O.
Schlumberger Technology Corporation
Tucker Philip
Y'Barbo Dough
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