Seawater injection has proven to be an effective means of enhancing hydrocarbon recovery. One concern for the installation of a carbon steel water injection flowline is the formation of corrosion debris that may result in well plugging and even more costly well work-overs. In this work, the effects of dissolved oxygen concentration and temperature on the formation and size distribution of corrosion generated particles The predicted particle volume and size distribution was then used to assess the risk of well plugging and determine if internal lining, coating or other corrosion control methods are needed.
Water flooding is a cost-effective and proven enhanced oil recovery technology. For obvious reasons, seawater is a preferred source for a subsea waterflood system. One issue for the seawater injection system is to avoid plugging the injection wells with particles carried by the injected seawater. In a carbon steel system, corrosion products (iron oxide) that form in the risers, flowlines and well tubing (if not CRA) are potentially one of the main contributors to plugging. Corrosion of carbon steel will occur in the seawater even with a trace amount of oxygen. Based on our operating experience, the acceptable permissible dissolved oxygen level in the seawater injection system is 10 parts per billion (ppb). During normal operation of the vacuum de-aeration tower and oxygen scavenger, the actual oxygen level is expected to be closer to 0 ppb. However, during upset conditions, the dissolved oxygen concentration can be as high as in untreated seawater, i.e. about 8 ppm. Many factors, e.g. operating temperature and pressure, dissolved oxygen concentration in seawater, ferrous concentration in seawater, surface condition of the steel and flow rate, significantly influence corrosion particle generation and size distribution in a seawater injection system. The purpose of this work was to identify the factors that would most likely contribute to carbon steel water injection well plugging and assess the well plugging risk over the project life with realistic operating and upset conditions of the de-aeration system. In this work, corrosion tests were performed on carbon steel coupons submerged in synthetic seawater to investigate the effects of varying dissolved oxygen concentrations and temperatures on the formation of particles generated by corrosion and to measure their sizes. Based on the laboratory results and a review of the operating and upset conditions of the de-aeration system, calculations were made to determine the volume of corrosion particles exceeding 17 µm in size that could form over the project life and migrate to the wells. The value of 17 µm was assumed as the maximum size of particle that would be allowed to prevent well plugging. The particle assessment helped to determine the risk of well plugging and if internal lining or other corrosion mitigation methods should be employed.
The test solution was synthetic seawater. The water chemistry is given in Table 1. The test gas was a mixture of nitrogen and oxygen. Two mixed gases were used in this work. For each gas, the calculation of gas composition was based on Henry's law in order to acquire the desired dissolved oxygen concentrations in seawater under the test conditions.