A chemical stimulation system that combines hydrochloric acid with chlorine dioxide can be used as a treatment fluid in water-injection wells that get impaired by deposition of solid residues.
Due to core test results the treatment seems to be more effective than the conventional acidizing system when the plugging material contains iron sulfide and bacterial agents, due to the strongly oxidative power of chlorine dioxide.
When produced waters are injected, the solids generally occlude not only the formation face but also the rock pores in the near wellbore area, producing important injectivity losses in short time periods. This formation damage mechanism usually takes place in many secondary recovery oilfields in Argentina. The permanent clean-up treatments substantially raise the injection maintenance costs and water treatment. That kind of treatments are used to restore injection losses and lessen surface pressures.
This system differs from previous treatments in that chlorine dioxide is not produced in-situ, resulting in economical improvement because of operative time and cost reduction.
The effectiveness of this system in the removal of formation damage has been demonstrated by core flooding laboratory tests under appropriate reservoir pressure and temperature conditions, and it is compared to acidizing alone.
Laboratory test results have led to the design of an operative program for the application of a pilot phase to be carried out in the following months.
In order to predict injectivity losses it is necessary to establish not only the type of formation damage but how it influences injection well efficiency. Internal or external cake formation are the usual damage mechanisms that affects injection performance.
Several parameters, such as particles properties (i.e size, shape, composition), fluid properties (injection rates) and pore system properties (permeability, pore throat size, tortuosity) determine which will be the damage mechanism and how severe it will be.(1, 2).
In most injection wells, suspended solids are mainly ferric hydroxide, iron sulfide (pyrite), calcium carbonate, calcium sulfate, clays, formation fines, oil and bacteria.
Sulfate reducing bacteria (S.R.B.) reduce injection water sulfate ions to sulfur ions. As a result, hydrogen sulfide (H2S) is produced and water corrosivity is increased. (3).
Sour corrosion allows the formation of iron sulfide, which is an excellent plugging agent. As a consequence pyrite generates important injectivity losses in very short periods. Several investigations have stated that also bacteria can certainly plug injection wells. (4)
Pyrite occurrence and solids deposition, which reduce injection rates, are usual problems in several Repsol YPF waterflooded fields. In such fields frequent acid treatments must be performed in order to restore the original injectivity. The injection water treatment cost is significantly increased by this situation.
A typical injection well injectivity decline example is shown in figure 1. Figure 2 shows total suspended solids (T. S. S.) and total sulfides evolution at the same well. It can be seen from both figures that when T. S. S. increase, total sulfides also increase. Acid stimulation frequency must be then also reduce to maintain injectivity.
