Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
2000-05-25
2003-03-18
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S263000, C507S219000, C507S254000, C507S261000, C507S927000, C507S929000, C166S311000, C166S312000
Reexamination Certificate
active
06534449
ABSTRACT:
FIELD OF THE INVENTION
The invention relates to treatment of surfaces in wellbores, and further concerns compositions and methods for improving surfaces in wellbores for further operations. The invention particularly concerns the provision of surfaces in wellbores adapted for improved bonding with cement.
BACKGROUND OF THE INVENTION
The use of oil based or synthetic fluids or muds is common in drilling and in other wellbore operations, for a variety of reasons. The oil based or synthetic fluids generally comprise invert emulsion fluids, where the continuous or external phase is predominantly organic or hydrocarbonaceous in nature and the inverse or internal phase is aqueous. For example, an oil based fluid or drilling mud may comprise one or more mineral and/or synthetic oils containing from 5 to 50 percent by volume of water, based on the total volume of fluid, the water being dispersed as very small droplets, usually less than a micron in diameter in the continuous oil phase. The stability of the invert emulsion is generally maintained by one or more additives present in the fluid, such as emulsifiers, emulsion stabilizing agents, and oil wetting agents.
While oil based fluids provide desired advantages or utility in particular circumstances, and, in some instances, will be the fluid(s) of choice, their advantages must be balanced in the situation against certain disadvantages accompanying their use. For example, use of such fluid(s) can pose difficulties in cementing procedures, or in operations designed for reworking a well. In the case of cementing, for example, a significant difficulty encountered is that the oil based fluid “oil wets” or coats wellbore surfaces, as well as casing and pipe run into the wellbore. For simplicity, as used hereinafter, the expressions “wellbore surface” or “wellbore surfaces” may be understood to encompass not only formation surface or surfaces extant in the drilled opening or wellbore, but may be taken to include formation surface(s) near the wellbore, such as designed fractures or cavities where gravel packing or other operations may be undertaken, along with the surfaces of equipment, e.g., casing, screens, pipe, etc, as may be present in the wellbore or in the formation near the wellbore.
The “oil wetting” of the formation surfaces by the oil based or synthetic fluids produces an oily residue or oily “cake” which renders the surfaces unsuited for many wellbore operations. For example, because cements utilized in wellbore cementing are formulated with aqueous liquid(s), initiation of cementing operations without removal of or otherwise mitigating the oil wet surfaces may result in poor cement bonding, thus defeating the purpose of the cementing operation. This problem is compounded by the fact that the formation surfaces may be porous and quite different from the non-porous metallic casing or equipment surfaces. Similar difficulties arise in gravel packing operations.
Again, in so-called open-hole reservoirs, production is initiated through the formation wall and screens directly. In such instances, any oil based fluid(s) cake that is not removed before or promptly after initiation of production may impair inflow through either the screens or the formation wall. Maximization of production and reduction of completion hardware damage requires, therefore, that measures be undertaken to reduce or remove the cake.
In the past, oily cake or oily residue has been removed in some cases by using a wash, perhaps from the same oil as the mud, which contained appropriate solvents and a mixture of surfactants. Another approach has employed a water-free mixture of surfactants and an alcohol. In some instances, various solvents, such as xylene, toluene, and low flash point terpenes, have been used. For a variety of reasons, including cost and increasing safety and environmental concerns, one or more of these options may be unattractive in a given case. In other instances, oil based fluid residue removal has not been sufficiently achieved, and, for example, cement bonding with a formation has not been satisfactory. As utilized hereinafter, the expression “oil-containing residue” is taken to include the oily “cake” on the formation surfaces and/or the oily residue left or remaining on equipment, casing, gravel, etc., in or in the formation near the wellbore. The invention addresses the problem of oil-containing residue on wellbore surfaces.
SUMMARY OF THE INVENTION
Accordingly, in one embodiment, the invention relates to a novel method or process comprising contacting a wellbore surface with an amount of wellbore fluid composition comprising a terpene composition and wetting surfactant, in an amount sufficient or effective to reduce oil-containing residue from the wellbore surface and water wet wellbore surface. The combination fluid composition supplied in effective amount thus comprises sufficient or effective amount of terpene composition to dissolve oil from the wellbore surface to a desired degree, and an amount of wetting surfactant effective to water wet wellbore surface. As employed herein, “water wet” indicates conditioning of wellbore surface to the extent that water adheres to at least a significant portion of the wellbore surface, as contrasted with oil wet or oil-containing surface which is significantly hydrophobic.
According to the invention, the terpene composition is selected from cyclic terpenes, and mixtures thereof; acyclic terpenes, and mixtures thereof; cyclic terpenoids having one or more benzenoid groups, and mixtures thereof; acyclic terpenoids having one or more benzenoid groups, and mixtures thereof; and mixtures thereof. Commonly available terpenes and terpenoids, many of which are alcohols, may be used, and are generally available in varying degrees of purity, generally available as mixtures. The preferred terpenes are biodegradable monoterpenes, such as d-limonene and alpha-pinene derivatives. In the preferred fluid composition, the terpene composition will be present in an amount of at least 85 percent by weight, more preferably at least 90 percent, and most preferably up to about 99 percent by weight of the blend. Unless otherwise specified or evident from the context, all percentages given herein are by weight, based on the weight of the fluid. The fluid composition may contain, if desired, minor quantities of components such as solvents, etc.
The wetting surfactant will be selected on the basis of capability to achieve the water wet condition mentioned, and the term “surfactant”, as utilized herein, is understood to include mixtures of appropriate surface active materials. In general, the wetting surfactant may be selected from anionic, which includes soaps (e.g., sodium stearate) whose active groups are anions; cationic, such as quaternary ammonium compounds; non-ionic, such as alcohol ethoxylates; and Zwitterionic, such as sulfobetaine. Commonly, the concentration in the fluid of the surfactant will range from 0.01 percent to 5 percent, possibly to 10 or 12 percent, preferably 0.1 percent to about 4 percent. The capability of a surfactant to water wet surfaces, such as wellbore surfaces, may be determined by testing, as described herein.
In a preferred aspect, to insure that water wetting of a wellbore surface is achieved to the desired extent, e.g., in the possibility that the surfactant has not water wet the wellbore surface under the wellbore conditions extant, the wellbore surface may further be contacted, after the above-mentioned contacting or treatment, with an aqueous fluid comprising a viscosifying organic polymer and wetting surfactant. This combination will be supplied in an amount sufficient to insure water wetting of the wellbore surface to the extent desired. In this further stage, the aqueous fluid will contain, as indicated, a viscosifying organic polymer (preferably synthetic) which is most preferably a water soluble polymer of an acrylic or methacrylic acid. The surfactant chosen may be the same as that for the first stage or spacer. The combination of the viscosifying polymer and the water wetting su
Bui Alexander
Cheung Ralph
Gilmour Alan
Menes Catherine
Mitchell Thomas
Nava Robin
Schlumberger Technology Corp.
Tucker Philip
LandOfFree
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