The present invention relates to a self-diverting retarded formation-dissolving composition for treating a subterranean formation, particularly at high temperatures. It also relates to methods for acid fracturing and matrix acidizing using the composition.
The flow of fluids through porous media, for example the production of fluids from wells, is governed by three principle factors: the size of the flow path, the permeability of the flow path, and the driving force. It is often necessary to stimulate the production of fluids from subterranean formations when wells are not producing satisfactorily. The failure to produce is typically due to an inadequate, or damaged, path for fluids to flow from the formation to the wellbore. This damage may be because the formation inherently has insufficient porosity and/or permeability, or because the porosity and/or permeability have been decreased (damaged) near the wellbore during drilling and/or completion and/or production.
There are two main stimulation techniques: matrix stimulation and fracturing. Matrix stimulation is accomplished, in sandstones, by injecting a fluid (e.g., acid or solvent) to dissolve and/or disperse materials that impair well production. In carbonate formations, the goal of matrix stimulation is to create new, unimpaired flow channels from the formation to the wellbore. Matrix stimulation, typically called matrix acidizing when the stimulation fluid is an acid, generally is used to treat only the near-wellbore region. In a matrix acidizing treatment, the acid used (for example hydrochloric acid for carbonates) is injected at a pressure low enough to prevent formation fracturing.
When acid is pumped into a subterranean formation, such as a carbonate (limestone or dolomite) formation, at pressures below the fracture pressure, the acid flows preferentially into the highest solubility or the highest permeability regions (that is, largest pores, vugs or natural fractures). Acid reaction in the high-solubility or high-permeability region ideally causes the formation of large, highly conductive flow channels called wormholes that form approximately normal to the fracture. The creation of wormholes is related to the rate of chemical reaction of the acid with the rock. High reaction rates, as observed between typical concentrations of unaltered mineral acids, such as HCl, and carbonates, tend to favor wormhole formation. Acids normally used in field treatments are highly reactive at reservoir conditions and tend to form a limited number of wormholes. A low reaction rate favors the formation of several small-diameter wormholes. It is desirable to take into account well and formation factors (such as temperature and formation composition) and adjust treatment parameters (such as acid strength and injection rate) so that dominant “wormholes” are formed which penetrate through the near wellbore area. However, unless the treatment is designed properly, wormholes are not formed. Instead, for example if the acid flux is too low, the acid reacts evenly with the formation, which is commonly called compact dissolution, dissolving all the rock near the wellbore and not penetrating deep into the formation and creating flow paths there.
In fracturing, on the other hand, a fluid is forced into the formation at a pressure above that at which the formation rock will part. This forcing creates a greatly enlarged flow path. However, when the pressure is released, the fracture typically closes and the new flow path is not maintained unless the operator provides some mechanism by which the fracture is held open. There are two common ways of holding the fracture open. In conventional propped hydraulic fracturing, the fluid that is used to generate or propagate the fracture is viscous and carries a solid proppant that is trapped in the fracture when the pressure is released, preventing the fracture from closing. In acid fracturing, also known as fracture acidizing, the fracture is generated or subsequently treated with an acid. In this case, however, the treatment parameters have in the past been adjusted so that wormholing did not occur. Instead, the object previously has been to etch the faces of the fracture differentially. Then, when the pressure is released, the fracture does not close completely because the differential etching has created an asperity between the faces so that they no longer match up and there are gaps where material has been removed. Ideally the differential etching forms flow channels, usually generally running along the faces of the fracture from the wellbore to the tip, that enhance production.
At present, matrix acidizing treatments are plagued by at least three serious limitations: (1) inadequate radial penetration; (2) incomplete axial distribution; and (3) corrosion of the pumping and well bore tubing. Although the following discussion will focus for the most part on matrix acidizing, similar problems affect acid fracturing methods such that the discussion is entirely applicable to both types of acid treatment.
The first problem with acid treatment, inadequate radial penetration, is caused by the reaction between the acid introduced into the formation and the material in the wellbore and/or formation matrix, with which it first contacts. The material and/or formation first contacted by the acid is usually at or near the wellbore such that the formation near the wellbore is adequately treated and 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. In fact, dissolution of the material and/or formation encountered by the acid may be so effective that the injected acid is essentially spent by the time it reaches a few inches beyond the wellbore.
A second problem that limits the effectiveness of matrix acidizing technology is incomplete axial distribution. This problem relates to the proper placement of the acid-containing fluid, i.e., ensuring that the fluid is delivered to the desired zone or zones (i.e., the zone that needs stimulation) rather than another zone or zones. More particularly, when a formation is injected with acid, the acid begins to dissolve the most reactive or first-contacted material in the wellbore and/or the matrix. Depending upon the reactivity of the acid with the matrix and the flow rate of acid to the reaction location, as one continues to pump acid into the formation, a dominant channel through the matrix is often created. As one continues to pump acid into the formation, the acid flows along that newly created channel as the path of least resistance and therefore leaves the rest of the formation substantially untreated. This behavior is exacerbated by intrinsic permeability heterogeneity (common in many formations), especially the presence of natural fractures and high permeability streaks in the formation. 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, hydrocarbon-bearing intervals within the zone to be treated are not contacted by enough acid to penetrate deep enough (laterally in the case of a vertical wellbore) into the formation matrix effectively to increase its permeability and therefore its capacity for delivering hydrocarbon to the wellbore. This problem of proper placement is particularly vexing since the injected fluid preferentially migrates to higher permeability zones (the path of least resistance) rather than to lower permeability zones, yet it is those latter zones that require the acid treatment (i.e., because they are low permeability zones, the flow of hydrocarbon through them is diminished). In response to this problem, numerous techniques have evolved to achieve more controlled placement of the fluid, diverting the acid away from naturally high permeability zones, and zones already treated, to the regions of interest.
Techniques to control acid placement (i.e., to ensure effective zonal coverage) can be roughly divided into either mechanical or chemical techniques. Mechanical techniques include ball sealers (balls dropped into the wellbore that plug the perforations in the well casing, thus sealing the perforation against fluid entry), packers (particularly straddle packers that plug a portion of the wellbore and thereby inhibit fluid entry into the perforations around that portion of the wellbore) and bridge plugs, coiled tubing (flexible tubing deployed by a mechanized reel, through which the acid can be delivered with more precise location within the wellbore), and bullheading (attempting to achieve diversion by pumping the acid at the highest possible pressure—just below the pressure that would actually fracture the formation). Chemical techniques can be further divided into techniques that chemically modify the wellbore adjacent the portions of the formation for which acid diversion is desired, and techniques that modify the acid-containing fluid itself. The first type involves, for example, particulate materials that form a reduced-permeability cake on the wellbore face that, upon contact with the acid, diverts the acid to higher permeability regions. These materials are typically either oil-soluble or water-soluble particulates that are directed at the high permeability zones to plug them and therefore divert acid flow to the low permeability zones. The second type includes foaming agents, emulsifying agents, and gelling agents. Mechanical methods and chemical methods that chemically modify the wellbore adjacent portions of the formation for which acid diversion is desired will not be considered further here.
Emulsified acid systems and foamed systems are commercially available responses to the diversion problem, but operational complexity sometimes limits their use. For instance, flow rates of two fluids and bottom hole pressure must be meticulously monitored during treatment. Gelling agents are commercially available, but are often undesirable in matrix acidizing since the increased viscosity makes the fluid more difficult to pump (i.e., the same resistance to flow that confers the pressure build-up in the formation and results in the desired diversion, actually makes these fluids difficult to place). Some commercially available systems are polymeric cross-linked systems, i.e., they are linear polymers when pumped, but a chemical agent pumped along with the polymer causes the polymers to aggregate or cross-link once in the wellbore, which results in gelling. Unfortunately, these systems leave a residue in the formation, which can damage the formation, resulting in diminished hydrocarbon production. In addition, the success of these systems is naturally dependent upon a cross-linking reaction that can be difficult to optimize so that it is delayed during pumping but maximized once the chemicals are in the bottom or end of the wellbore, or in the formation. This reaction is easily perturbed by formation chemistry, contaminants in the pumping equipment, and other factors.
Viscoelastic surfactant based gelling systems can avoid these problems. One viscoelastic surfactant based gelling system is disclosed in U.S. Pat. Nos. 5,979,557 and 6,435,277, which have a common Assignee as the present application. Another viscoelastic surfactant based gelling system is disclosed in U.S. Pat. No. 6,399,546 and U.S. patent application Ser. No. 10/065,144, which also have a common Assignee as the present application. Viscoelastic diverting acids (VDA's) were developed for carbonate matrix acidizing and may contain certain zwitterionic surfactants, such as those based on betaines (described in U.S. Pat. No. 6,258,859 and referred to as BET surfactants), an acid, and (for some BET surfactants) a co-surfactant or (for some BET surfactants) an alcohol. The initially injected fluid has a nearly water-like viscosity, but after a considerable portion of the acid is spent, or consumed, in a carbonate formation that reacts with a large amount of acid, viscosity increases substantially. Thus, when first injected, VDA's enter the most permeable zone(s), but when they gel, they block that zone or zones and divert subsequently injected fluid into previously less-permeable zones. The success of such systems depends upon the ability of the formation to react with a large amount of acid. Consequently, they are most useful with carbonates that have a large capacity to react with acid.
Another limitation of acid treatments is the corrosion of the pumping equipment and well tubing and casing caused by contact with the acid (made worse by the use of concentrated solutions of mineral acids). To solve the corrosion problem, conventional acid treatments often add a corrosion inhibitor to the fluid. However, corrosion inhibitors can significantly increase the cost of acidizing treatments.
Another problem with acid treatments is iron precipitation, especially in sour wells (i.e., wells in which the hydrocarbon has a relatively high sulfur content) or carbonate formations. There is a tendency for iron sulfide scale to form in boreholes and/or formations, especially in sour wells. The acid used to treat the well can dissolve the iron sulfide, but in the process hydrogen sulfide is generated, which is toxic and stimulates corrosion. In addition, the dissolved iron tends to precipitate, in the form of ferric hydroxide or ferric sulfide, as the acid in the treatment fluid becomes spent and the pH of the fluid increases. Precipitation of iron is highly undesirable because of damage to the permeability of the formation. Therefore, acid treatment fluids often contain additives to minimize iron precipitation and evolution of hydrogen sulfide, for example, by sequestering the iron ions in solution using chelating agents such as ethylenediaminetetraacetic acid (EDTA).
U.S. Pat. No. 4,888,121 discloses an acidizing composition that includes an acid such as HCl; an iron sequestering agent such as citric acid, EDTA, or nitrilotriacetic acid (NTA); and a sulfide modifier such as formaldehyde. This composition is stated to inhibit precipitation of ferric hydroxide, ferrous sulfide, and free sulfur during the well acidizing treatment. Although the treatment fluid described in that patent can help control iron precipitation, in some situations effective control requires the use of so much material that the treatment cost becomes excessive; this is especially true for treatment fluids comprising EDTA, which has relatively low solubility in acid (e.g., pH≦4).
Another limitation of known acid treatments is their susceptibility to the temperature of the subterranean formation. The effects of high formation temperatures, for instance, vary widely according to the details of the particular fluid treatment. In some acid treatments, the high temperature has a tendency to accelerate corrosion of metal in the wellbore. In other fluids, the intended viscosity changes to do not occur such that the acid does not serve the intended purpose of propping and/or diverting.