Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
2000-05-03
2002-08-20
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S090000, C507S131000, C507S927000, C507S939000
Reexamination Certificate
active
06436880
ABSTRACT:
TECHNICAL FIELD OF THE INVENTION
This invention relates to the stimulation of hydrocarbon wells and in particular to acid fluids and methods of using such fluids in treating a subterranean formation having low permeability.
BACKGROUND OF THE INVENTION
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.
Hence, 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. This damage often 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 formation), 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.” 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 fracture the formation, thereby creating a large flow channel though which hydrocarbon can more readily move from the formation and into the wellbore. The present invention is directed to all three processes.
Thus, the present invention relates to methods to enhance the productivity of hydrocarbon wells (e.g., oil wells) by creating alternate flowpaths by removing portions of a wellbore coating, dissolving small portions of the formation, or removing (by dissolution) near-wellbore formation damage. Generally speaking, acids or acid-based fluids are useful for this purpose due to their ability to dissolve both formation minerals 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.
The most common agents used in acid treatments of wells are mineral acids such as hydrochloric acid, which was disclosed as the fluid of choice in a patent issued over 100 years ago (U.S. Pat. No. 556,669, Increasing the Flow of Oil Wells). At present, hydrochloric acid is still the preferred acid treatment in carbonate formations. For sandstone formations, the preferred fluid is a hydrochloric/hydrofluoric acid mixture.
At present, acid treatments are plagued by three limitations: (1) radial penetration; (2) corrosion of the pumping and well bore tubing, and (3) the precipitation of iron dissolved from the formation, tubing, or surface equipment in the course of treatment.
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 formation matrix (e.g., sandstone or carbonate), and/or the wellbore coating. In the case of treatments within the formation (rather than wellbore treatments) the portion of the formation that is near the wellbore and 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, because 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 injection 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, it has been calculated that 117 gallons of acid per foot is required to fill a region five feet from the wellbore (assuming 20% porosity and 6-inch wellbore diameter). See, Acidizing Fundamentals, 5,6, in Acidizing Fundamentals SPE (1994). Yet a far greater amount of acid than this would be required to achieve radial penetration of even a single foot, if a conventional fluid (HCl) were used.
Similarly, in carbonate formations, the preferred acid is hydrochloric acid, which again reacts so quickly with limestone and dolomite (primary components of carbonate formations) that acid penetration is limited to a few inches to a few feet. In fact, due to such limited penetration, it is believed that matrix treatments are limited to bypassing near-wellbore flow restrictions. Yet low permeability at any point along the hydrocarbon flowpath can impede flow (hence production). Ibid. Therefore, because of the prodigious fluid volumes required, these treatments are severely limited by their cost.
In response to this “radial penetration” problem, organic acids (e.g., formic acid, acetic acid) are sometimes used, since they react more slowly than mineral acids such as HCl. However, organic acids are an imperfect solution. First, they are far more expensive than mineral acids. Second, while they have a lower reaction rate, they also have a much lower reactivity—in fact, they do not react to completion, but rather an equilibrium with the formation rock is established. Hence one mole of CHl yields one mole of available acid (i.e., H
+
), but one mole of acetic acid yields substantially less than one mole of available acid.
A third general class of acid treatment fluids (the first two being mineral acids and organic acids) have evolved in response to the need to reduce corrosivity and prolong the migration of unspent acid radially away from the wellbore. This general class of compounds is often referred to as “retarded acid systems.” The common idea behind these systems is that the acid reaction rate is slowed down, for example, by emulsifying the acid with an oil and a surfactant, or oil-wetting the formation. These approaches also have problems that limit their use.
Emulsified acids are seldom used in matrix acidizing since the increased viscosity makes the fluid more difficult to pump. Similarly, chemically retarded acids (e.g., prepared by adding an oil-wetting surfactant to acid in an effort to create a barrier to acid migration to the rock surface) often require continuous injection of oil during the treatment. Moreover these systems are often ineffective at high formation temperatures and high flow rates since absorption of the surfactant on the formation rock is diminished. Emulsified acid systems are also limited by increased frictional resistance to flow.
The second significant limitation of acid treatments is the corrosion of the pumping equipment and well tubings and casings, caused by contact with the acid (worse in the case of more concentrated solutions of mineral acids). To solv
Jeffery Brigitte
Menes Catherine
Nava Robin C
Schlumberger Technology Corporation
Tucker Philip
LandOfFree
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