Several prediction models for CO 2 corrosion of oil and gas pipelines have been developed. Most of the models take limited account for multiphase flow effects, and some of the models require separate fluid flow calculations. For multiphase pipelines the variation in flow regime, liquid flow velocity, water wetting and temperature along the pipeline will have a large effect on the prediction of pipeline corrosion. Three of the openly available CO 2 corrosion prediction models have been implemented in a commonly used and comprehensive three-phase fluid flow model. This gives the possibility to simulate corrosion rate profiles along the pipeline together with flow regime and temperature, pressure, and flow velocity profiles. The implementation of corrosion models in a full multiphase flow model opens for better modelling of the effects of flow regime, water cut and especially water wetting during prediction of CO 2 corrosion in oil and gas pipelines.
Different oil companies and research institutions have developed a large number of prediction models for CO2 corrosion of carbon steel in oil and gas wells and pipelines. Many of these models take flow-related parameters like liquid velocity or water, oil and gas production rates into account. However, most of the models are point models, i.e. they can only be used to predict the corrosion rate at a given location in a well or pipeline where the temperature, pressure, water chemistry and flow conditions are specified. The models either take liquid velocity as input or assess the flow effect on corrosion by a simplified fluid flow calculation in a point. In order to perform a corrosion evaluation for a specific well or pipeline it is therefore often necessary to first perform a fluid flow simulation with a separate fluid flow model and then use the results from this simulation as input for running a corrosion model at different points in the well or pipeline.
There is obviously a need to combine fluid flow models and corrosion models into a single package. This can be done by including fluid flow equations in a corrosion model, and this has been done to a certain extent for some corrosion models. The other approach is to implement corrosion models in an existing fluid flow model, and this approach has been used in the present work. There are several advantages with this approach. Even the most complex CO 2 corrosion models are usually smaller and simpler programs than the extensive fluid flow models available. Comprehensive fluid flow models are already used by the oil companies at the field design stage for wells and pipelines, and a corrosion module built into the fluid flow model already in use in the company could simplify corrosion evaluations significantly.
In the present work the 1993 and 1995 versions of the de Waard model l' z and the NORSOK M-506 model 3' 4 have been implemented into a commonly used and comprehensive three-phase fluid flow model s. The de Waard model is probably the most widely used CO2 corrosion model, while the M-506 model is one of the most recent models and is now extensively used in Norway. Both the de Waard models and the M-506 model are openly available. They were therefore chosen as typical examples of corrosion models in this work, where the objective has been to demonstrate the possibility of including corrosion predictions in an existing multiphase transport model. The temperature, pressure and liquid flow velocity profiles from the fluid flow model are used to calculate CO2 partial pressure, pH and corrosion rate profiles along the pipeline. This approach also opens up the possibility to use the prediction of flow regime and water wetting in the flow model in the corrosion calc
