New Treating Technique to Remove Bacterial Residues From Water-Injection Wells
Authors: Crow C.W. 
Published: December 2007

CROW, C.W., DOWELL DIV. DOW CHEMICAL CO. MEMBER AIME TULSA, OKLA.

Abstract
A new treating technique was devised for use in water-injection wells whose injectivity has been impaired by deposition of bacterial residues. This technique employs a two-stage treatment, using a combination of a strong oxidizing agent followed by acid. The treatment is effective against bacterial and other nonhydrocarbon organic residues that normally are not removed by conventional acidizing or solvent treatments.
It has long been known that much of the injection water used in waterflooding contains bacteria or other microorganisms. These microorganisms have been shown to produce extensive formation damage in the rock matrix produce extensive formation damage in the rock matrix around the wellbore, thereby reducing water-injection rates. Previous studies demonstrated that formation damage of Previous studies demonstrated that formation damage of this type can be removed only partially by acidizing since only the inorganic portion of the plugging deposit is reactive. To dissolve the organic matter present, a strong oxidizing solution is necessary. The oxidizing solution found to be most effective in this application is an inhibited 5 percent solution of sodium hypochlorite. Although percent solution of sodium hypochlorite. Although hypochlorite solutions normally are quite corrosive to steel, a method has been found to inhibit them so that they can be used in standard oilfield equipment. A two-stage treating technique using an inhibited sodium hypochlorite solution followed by acid has been found to be extremely effective in treating water-injection wells. Laboratory data and comparative well treatment results are presented to show the effectiveness of this treatment as compared with acidizing alone.

Introduction
Secondary recovery of oil by waterflooding commonly is plagued by injection problems, one of the most important of which is the tendency of porous rock around the wellbore to become partially plugged. Investigators have shown that this plugging is the result of both the deposition of inorganic materials such as ferric hydroxide and ferrous and ferric sulfide, and the formation of bacterial deposits.
Numerous investigations have found that bacteria are very effective in causing plugging of formation faces in water-injection wells. Studies also have shown that most injection systems contain microorganisms of some type. Of the various microorganisms commonly found in oilfield injection waters, almost all have been shown to produce some degree of formation damage. Bacteria-laden waters often are responsible for much of the reduction in injection rate observed in input wells. Examination of a typical injection water from one lease revealed that there was about 0.5 oz of bacterial cellular material being added to each well for every 100 bbl of water injected. In time, this weight of slimy material is sufficient to cause considerable plugging of the formation face. In another study, an plugging of the formation face. In another study, an injection water was filtered through a permeable glass disk and residue from the filter was recovered and analyzed. This analysis showed the residue contained 60 per cent inorganic material and 40 per cent organic material that apparently was of bacterial origin.
Bacterial plugging occurs not only on the face of the formation. but also within the matrix of the rock. Although there is disagreement as to the maximum depth of penetration. Studies have shown that live bacteria may penetration. Studies have shown that live bacteria may migrate within cores at a rate as great as 1 1/2 in./day. There is evidence of extensive formation penetration by bacteria in both producing and gas storage wells. The large amounts of hydrogen sulfide produced by some gas wells, which earlier had produced none, indicates infection of the formation by sulfate-reducing bacteria.
Although bacterial plugging is a commonly recognized phenomenon, it seldom is considered in the design of phenomenon, it seldom is considered in the design of stimulation treatments for water-injection wells. Acidizing frequently will increase injectivity of wells damaged by bacteria, but only partial restoration of the original permeability is obtained. In core test studies conducted by permeability is obtained. In core test studies conducted by Kalish, various procedures were used in an attempt to restore permeability to bacteria-damaged cores. Of the techniques studied, acidizing followed by reverse flow provided the best results. However, this treatment restored provided the best results. However, this treatment restored only 20 to 65 per cent of the original permeability. Kalish's examination of bacteria exposed to hydrochloric acid showed that individual cells tended to disperse and shrink; however, they did not actually dissolve. Cerini also studied methods of dissolving bacterial residues. He found that this type of material was not soluble in hot hydrochloric acid, but was dissolved by boiling sodium hydroxide or oxidizing solutions such as aqua regia and boiling mixtures of sulfuric and chromic acid.
Oxidizing agents such as calcium and sodium hypochlorite have been used in treating injection wells damaged by bacteria. The beneficial effect of these materials has been attributed to the oxidation of living or dead bacterial cells or other easily oxidized organic matter produced as the result of bacterial action.
JPT
P. 475