Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
1998-12-01
2002-02-26
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S237000, C507S240000, C507S243000, C507S257000, C507S203000, C507S277000, C507S933000
Reexamination Certificate
active
06350721
ABSTRACT:
TECHNICAL FIELD OF THE INVENTION
This Invention relates to the stimulation of hydrocarbon wells and in particular to the fluids and methods used in treating a damaged formation using acid-type fluids, and other fluids of similar function.
BACKGROUND OF THE INVENTION
1. Introduction to the Technology
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 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.” 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 though which hydrocarbon can more readily move from the formation and into the wellbore. The present Invention is directed primarily to the second 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. Generally speaking, acids, or acid-based fluids, are useful in this regard 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.
2. The Prior Art
At present, acid treatments are plagued by three serious limitations: (1) radial penetration; (2) axial distribution; and (3) corrosion of the pumping and well bore tubing. 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, 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 would that this would be required to achieve radial penetration of even a single foot, if a conventional fluid (HCl) were used. Similarly, in carbonate systems, the preferred acid is hydrochloric acid, which again, reacts so quickly with the limestone and dolomite rock, that acid penetration is limited to 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.
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. Organic acids are an imperfect solution though—since they react incompletely, plus they are expensive.
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 second general class of compounds are often referred to as “retarded acid systems.” The common idea behind these systems is that the acid reaction rate is slowed down for instance, by gelling the acid, oil-wetting the formation, or emulsifying the acid with an oil. Each of these approaches also has significant problems which limit their use.
Gelling agents, though they should, in theory, retard acid reaction rate, 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 axial distribution. This refers to the general desirability to limit the movement of the acid solution axially, so that it does not intrude upon other zones, in particular, water-saturated zones. Any fluid that migrates away from its intended target (i.e., the desired hydrocarbon flowpath, or the damaged region) means that more fluid must be pumped into the formation, therefore increasing treatment cost. A conventional mineral acid treatment (e.g., HCl) has very high miscibility with an aqueous phase relative to the organic- (or hydrocarbon-) bearing phase, and therefore the potential (and undesirable) migration of the HCl-based fluid into a water-saturated zone, is a serious concern. Therefore, an acid fluid having very low miscibility with an aqueous (water) phase is highly desirable.
Another ubiquitous problems that limits the desirability of acid
Card Roger J.
Fu Diankui
Mitchell Thomas O.
Nava Robin C.
Schlumberger Technology Corporation
Tucker Philip
Y'Barbo Douglas
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