Earth boring – well treating – and oil field chemistry – Well treating – Contains inorganic component other than water or clay
Reexamination Certificate
1998-11-04
2001-06-19
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains inorganic component other than water or clay
C507S267000, C507S939000, C252S387000, C252S389620
Reexamination Certificate
active
06248700
ABSTRACT:
FIELD OF THE INVENTION
This invention generally relates to preventing or reducing corrosion of metallic equipment used in the exploration of subterranean formations and to methods of using inventive aqueous base fluids to achieve this result. Certain aqueous base fluids are used in accordance with the invention in drilling, drill-in, completion, work-over, packer, well treating, testing, spacer, and hole abandonment fluids. More specifically, this invention is directed to (1) brine fluids exhibiting reduced corrosivity toward metallic fluid handling equipment, improved well control, better shale stability, and increased thermal stability for polysaccharide additives, and (2) methods of inhibiting corrosion of metallic pipe and drilling equipment using a base fluid selected in accordance with the invention.
BACKGROUND OF THE INVENTION
Oil well tubular or pipe corrosion is a major concern for the drilling industry. Corroded pipe and other fluid handling equipment is expensive to replace, failure and/or replacement of equipment typically results in significant losses in well production, and damaged equipment and resulting lost fluid can be hazardous to the operators and the environment. Corrosion is a significant concern in this industry because metallic drilling/fluid handling equipment is exposed to harsh conditions, and fluids used to prepare a well for production are corrosive to fluid handling equipment.
Most fluids used in drill operations include halide brines as base fluids because these brines exhibit a number of desirable features for such use. For example, halide brines can be prepared that have relatively high densities, and the use of halide brines typically results in less formation damage than other base fluids. Conventional brines, however, are highly conductive media and promote corrosion of steel. Furthermore, many well fields have high concentrations of carbon dioxide (“CO
2
”) and/or hydrogen sulfide (“H
2
S”) dissolved in the strata and, consequently, these substances are present in the well bore fluid. Carbon dioxide and H
2
S can be highly corrosive to well equipment—particularly to steel pipes. Thus, when selecting equipment for use in an operation and when selecting a base fluid for use, one must take into account whether CO
2
and/or H
2
S are present and also consider what measures may be taken to counter the corrosivity of halide brines
In some cases, particularly where CO
2
and/or H
2
S are not present in an oil field, halide-induced corrosion can be reduced to acceptable levels, for example, by the selection of pipe made from carbon steel (which is more resistant to halide brine-induced corrosion than stainless steel) and by adding corrosion inhibitors to the fluid. There are a variety of inhibitors available to prevent this type of corrosion, and it is believed that these inhibitors affect corrosion by reducing the potential of the corrosion reaction or by removing some of the agents that initiate corrosion, such as dissolved oxygen. However, as temperature increases, as would occur as well bores reach depths of about 15,000 feet and deeper, corrosion inhibitors often become ineffective or require unacceptably high concentrations for adequate corrosion inhibition.
Additional factors must be considered, however, in an environment comprising CO
2
and/or H
2
S. Carbon steel is highly susceptible to CO
2
-induced corrosion. Therefore, in CO
2
environments, Ikeda, et al. recommend using 2% Cr steel at temperatures below 140° F. (60° C.), 9% Cr up to 212° F. (100° C.), and 13 Cr up to 302° F. (150° C.). (A. Ikeda et al., “CO
2
Corrosion Behavior and Mechanism of Carbon Steel and Alloy Steel,” Paper No. 45, Corrosion 83, Anaheim, Calif., 1983). However, since most conventional completion brines contain halides that are known to cause pitting-type corrosion in some stainless CRA (corrosion resistant alloy) steels, (M. G. Fontana et al., Corrosion Engineering, McGraw-Hill, 1967), the prevention or reduction of CO
2
-induced corrosion by using stainless steel results in a greater risk of halide-induced corrosion.
Therefore, an operator of drilling and fluid control equipment is left with a difficult decision in an oil field that comprises CO
2
. By solving one problem, another is created. The operator can (1) prevent the corrosion problem by perforating in oil-based mud and accept the formation damage that occurs, or (2) complete the well with a halide brine, using stainless steel equipment, and accept the possibility of replacing the stainless steel pipe when it fails or corrodes to an unacceptable level from contact with halides, or (3) use a carbon steel pipe and keep replacing the pipe and related equipment as it fails in the corrosive carbon dioxide environment. In some instances, use of very costly Hastelloy tubing may provide a partial solution to the corrosion problem so that the completion can be done in halide brine, but this cannot prevent corrosion of the well casing, which is typically carbon steel.
In view of this background, there is a great need in the art for methods and compositions that can be used in connection with drilling and well-bore fluids irrespective of the type of steel present in tubulars, pipes and other metallic equipment (i.e., stainless steel or carbon steel) to reduce corrosion thereof. The present invention provides such compositions and methods, thereby overcoming corrosion problems described above. Perhaps most remarkably, the invention may be used in an environment comprising CO
2
and/or H
2
S to significantly prolong the useful life of metallic equipment, particularly carbon steel pipe and related fluid handling equipment.
SUMMARY OF THE INVENTION
Thus, there are provided in the present invention methods of inhibiting corrosion on a metal surface in contact with a wellbore treatment fluid containing a brine, the method comprising: Providing an aqueous composition including a carboxylate salt; contacting a metal surface with the aqueous composition; and maintaining a concentration of about 1.0 wt % to about 84 wt % of the carboxylate salt in the aqueous composition for a time sufficient to inhibit corrosion on the metal surface.
There are also provided methods of conditioning a metal surface in contact with an aqueous brine having therein carbon dioxide, the method comprising: Providing an aqueous composition including a carboxylate salt, contacting the metal surface with the aqueous composition for a time sufficient to condition the metal surface.
The invention also provides a clear base fluid comprising sodium bromide and sodium formate in a ratio whereby the fluid has a density of from about 10.5 ppg to about 11 ppg, and wherein the fluid exhibits a true crystallization temperature lower than a substantially pure sodium bromide or sodium formate brine of substantially the same density.
Accordingly, it is an object of the present invention to provide compositions and methods for preventing or reducing corrosion of metallic equipment used in the exploration of subterranean formations.
It is also an object of the invention to provide compositions which advantageously have low true crystallization temperatures, and which therefore may be advantageously used in a relatively cold environment.
Additional features, objects and advantages of the invention will be apparent from the specification and the Figures appended hereto.
REFERENCES:
patent: 2722516 (1955-11-01), Merker
patent: 4401624 (1983-08-01), Atwater
patent: 4618539 (1986-10-01), Jahnke et al.
patent: 5202058 (1993-04-01), Riggs, Jr.
patent: 5330683 (1994-07-01), Sufrin
patent: 5407471 (1995-04-01), Rohr et al.
patent: 5507861 (1996-04-01), Caupin et al.
patent: 5510057 (1996-04-01), Riggs
patent: 5783527 (1998-07-01), Dobson, Jr. et al.
patent: 5789351 (1998-08-01), Ahmed et al.
patent: 2257703 (1975-08-01), None
patent: 97/26311 (1997-07-01), None
Esteso, M.A. et al., Journal of Solution Chemistry, vol. 20, No. 4, pp. 417-429, (1991).
Horton Robert L.
Vollmer Daniel P.
Baker & Botts L.L.P.
Great Lakes Chemical
Tucker Philip
LandOfFree
Carboxylate-based well bore treatment fluids does not yet have a rating. At this time, there are no reviews or comments for this patent.
If you have personal experience with Carboxylate-based well bore treatment fluids, we encourage you to share that experience with our LandOfFree.com community. Your opinion is very important and Carboxylate-based well bore treatment fluids will most certainly appreciate the feedback.
Profile ID: LFUS-PAI-O-2461605