Corrosion inhibitors are used to protect deepwater facilities against internal corrosive attack. Corrosion can particularly occur in the slug flow regime. In this article, the development and testing of corrosion inhibitors to protect against slug flow in subsea deepwater locations is described. A testing protocol for corrosion inhibitors that tests for performance in the appropriate flow regime and for compatibility with process fluids and system facilities is described.


As oil and gas are produced from deeper offshore locations in subsea configurations, the inhibitor performance for protection of the flowlines becomes a key concern. This is a concern eventhough the CO2 content of these projects are less than 0.5% CO2. We have found that not only is the corrosion protection performance of the inhibitor key, but also that other factors are important. Inhibitor evaluation should take into account a number of concerns. Among these is the flowline production flow regime. A number of recent subsea projects have been installed that produce in the slug flow regime. Conditions in slug flow require a careful choice of corrosion inhibitor to both protect the system and satisfy the constraints on a production chemical imposed by operations in a deepwater environment. In this paper, a hypothetical oil and gas production system is described, detailing the type of flow regime seen in the system and the risk due to internal corrosion. After assessment of the risk of corrosion, appropriate tests are used to determine the performance of corrosion inhibitor at places where the system is at highest risk. It is equally important to ensure that the corrosion inhibitor is compatible with system fluids and system materials. There are not many corrosion inhibitors that can satisfy the wide variety of constraints mentioned above. In this paper information on an inhibitor that satisfies this complete set of constraints is provided.

Deepwater System Conditions and a Typical Subsea System

A detailed summary of deepwater conditions has been published previously.l However, in this paper, a subsea flowline system is modeled and a corrosion inhibitor is developed for the system. The data for this hypothetical system are provided in Table 1. Several features distinguish this system from the hypothetical system previously considered, namely, higher temperature, higher pressure, higher mole percent of carbon dioxide, and fluid production. The values of several parameters that have been calculated using multiphase flow modeling are presented in Table 2. The flow modeling for CO2 corrosion utilized a model developed in Shell over a number of years. This corrosion model software is used as the start for assessing risk in a line in CO2 service. It uses several published methods of predicting corrosion rates for carbon steel due to carbon dioxide in oil field environments. 2-8

Results from this model using one case are shown in Figure

1. The figure is a plot that shows the corrosion rate, the pH and the mixture velocity as a function of distance from the sled (zero point on the x-axis) to the riser to the top of the platform (-8000m). An examination of the results shows the system can be divided into the following regions for corrosion risk assessment.

1. The sled region

2. Horizontal Section

3. Riser

The model predicts high corrosion rates as the flow enters the sled, where no consumption of CO2 has occurred and where the pH value is lowest (pH-5). As the flow continues down the line, the corrosion rate decreases and pH values increase (pH-6). In the horizontal section the corrosion rate decreases and continues to drop until it reaches the riser where corrosion rates

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