The field of the present invention is treatment of high pressure water injection wells.
The oil industry uses a variety of techniques to maximize the recovery of oil from any particular oil formation. One of the methods so used is the injection of water under high pressure at a point removed from the site of the oil removal. Large amounts of water are injected under high pressure into the oil-producing sands and are removed at the oil well site along with the resident oil. Such methods typically require up to twenty parts water per part oil recovered. Given this large amount of required water, many oil producers utilize the nearest large source of water, which can be a surrounding ocean, nearby bay, or water produced with the oil. Little care is taken to purify the injection water and, therefore, a wide variety of impurities are often injected in the water injection well.
The constant high volume flow of impure water and the warm, incubator-like environment of oil field water treatment systems encourages the uncontrolled growth of biomass--the source of many costly problems. Bacterial growth, if left unchecked, causes: formation of hydrogen sulfide, a toxic and corrosive gas that eats through piping in water and vapor recovery systems; accumulation of gummy biomass that adheres to surfaces and filter media and substantially reduces equipment efficiency; formation of abrasive iron sulfide that wears injection pumps, decreases injectivity, fouls flow lines and causes corrosion; all increasing operating costs and lowering oil production. The resultant build-up at the screen leading from the casing into the oil-producing sands constricts the flow of water through the tubing and screen. As the flow is constricted, less water can be pumped through the system, leading to decreased oil production. If the water injection tubing and screen are not cleaned out periodically, the screen can become entirely obstructed.
A conventional treatment against bacterial growth is to use such substances as glutaraldehyde, acrolein and quaternary amines which are nonoxidizing compounds. They are used to control biomass by altering the permeability of the cell membrane of the microorganisms and interfering with their vital life processes. The application of these products, however, does nothing for the plugging, fouling, deposits and corrosion that have been caused by the biomass and bacterial by-products.
Under the present state of the art, the commonly accepted procedure for cleaning out such water injection casings is to inject hydrochloric acid into the water injection well. The hydrochloric acid, by keeping the pH of the system low, solubilizes some of the unwanted materials so that they can be washed out of the water injection well. This prior art method suffers from several problems. First, such mixtures can be highly corrosive and will corrode the water injection well. In addition, such a mixture has little or no effect on any biomass that may have built up. Such biomass is often the primary obstructor. Finally, this method of clean-out is relatively expensive.
Also relevant as background to the present process is an overview of the compound chlorine dioxide. Chlorine dioxide was discovered in 1814 and has achieved considerable commercial significance in the bleaching of pulp, textiles, flour, etc., water purification, etc. Chlorine dioxide is, under certain conditions, inherently explosive and has necessitated extensive controls on the reaction conditions and on the reaction effluent. In the gaseous state, chlorine dioxide is explosive at concentrations above about ten percent in air. Typically, where large amounts of chlorine dioxide are desired, sodium chlorate or sodium chlorite has been the source material. The sodium chlorate is contacted with chemicals such as sulfur dioxide, oxalic acid, hydrochloric acid, organic reducing agents, etc., under carefully controlled conditions to produce chlorine dioxide containing more or less chlorine depending on the particular conditions employed. For smaller quantities, sodium chlorite has been used to react with chlorine to generate more pure chlorine dioxide. Again, rather extensive safety precautions have been required in the past.
For a good review of the chemistry, physical properties, and uses of chlorine dioxide, see Masschelein, W. J. "Chlorine Dioxide--Chemistry and Environmental Impact of Oxychlorine Compounds", Ann Arbor Science Publishers, Inc. (1979), the disclosure of which is incorporated herein by reference. Given the explosive tendencies of both chlorine dioxide and sodium chlorite, prior art methods of production involved various precautions. For example, U.S. Pat. No. 2,871,097 to Rapson discloses the use of inert gases "in an amount sufficient to maintain the effluent gases non-explosive".
Chlorine dioxide has found its way into limited use in the oil production industry. This material has been recognized for the treatment of oil field produced fluids. Reference is made to Canadian Patent No. 1,207,269, issued July 8, 1986, the disclosure of which is incorporated herein by reference. Reference is also made to Smeck, U.S. Pat. No. 4,077,879, issued Mar. 7, 1978. In these processes, the chlorine dioxide is typically used for surface treatment of oil field produced fluids.
Therefore, there has existed the need for a process to treat water injection or oil-producing wells that will remove biomass as well as other deposits caused thereby and avoid excessive corrosion of the water casing and other parts without creating dangerous operating conditions.