Optimizing CAPEX and OPEX for High CO2 and H2S Field by Using Mechanistic Corrosion Modelling Approach

The gas contaminants especially CO2 and H2S from the well is a major threat to oil and gas production facilities and pipeline. Developing this type of reservoir cost enormous CAPEX and OPEX due the need for expensive materials or the need of continuous chemical injection. This paper outlines the opportunity of cost optimization for future field development and operational through mechanistic corrosion modelling approach. This method was embedded to an in-house corrosion prediction model that was first developed by collaboration with Ohio University in 2008 with capability to predict corrosion rate for partial pressure more than 20bar of CO2 and up to 1bar of H2S. The model validation was performed based on actual field production operated at 55°C and 22 bar of CO2 partial pressure followed the methodology as outlined in NACE paper C2012-0001449. Upon successful validation, the model has been deployed to assist an Operator of an offshore pipeline in Southeast Asia, operating at 97°C and 17 bar of CO2 partial pressure, to ascertain the risk due to CO2 corrosion and review the original pipeline design adequacy. Subsequently, the model has been utilized for an Operator of onshore facilities in Middle East to address specific issue encountered during the final stage of development for one of the wellpad in which the wells are expected to experience increase of H2S from 100ppm in original design to more than 1000ppm during actual production. This process changes raised a serious concern on the integrity of the materials as potential corrosion issue and the need for corrosion mitigation such as H2S Scavenger injection was not originally considered during early stage of engineering. The corrosion rate from the model has been validated against the intelligent pigging (IP) data and proven to be able to predict corrosion rate with +20% accuracy and more than 99% confidence level for CO2 partial pressure up to 25 bar with the presence of H2S. Based on deployment and utilization of the model, the high confidence in the model ability to accurately predict the corrosion rate will lead to potential CAPEX and OPEX optimization for the field development and during operational stage.

Finite Element Method for Thin Film Corrosion Modelling: Where We Advanced and Where We would like to Advance?

Thin film corrosion is a serious issue in almost every sector. Thus, simulation of corrosion under thin electrolyte films has always been of high interest as experimental studies are often challenging. Thus far, progress has been made to model the effect of several important factors on thin film corrosion rates. Some of these parameters are electrolyte thickness, electrolyte composition, chemical reactions in the electrolyte, electrode size and change in electrode size, environmental parameters, and corrosion products deposition. However, these parameters are mainly drawn from different studies and have not been modelled concurrently in a single simulation study, making the thin film corrosion model far from being complete yet. Therefore, despite the many efforts so far, thin film corrosion modelers still strive to push the modelling edges further. This paper takes into account some of the highlighted recent advances in thin film corrosion modelling based on the mentioned parameters to provide a perspective on not only how far the field has come, but also how far it still is from a complete thin film corrosion model. Discussions have also been made on future needs and prospects to advance the thin film corrosion models further.

Offshore Oil and Gas Pipeline: Flow Assurance and Corrosion Modelling for Inspection Prioritization

Flow modelling and corrosion risk assessment are used to study a challenging multiphase pipeline, where the main focus is the identification and prioritization of critical locations for direct inspection (DA). Through the internal corrosion direct assessment (ICDA), flow modelling sensitivity studies is carried out to identify critical locations with risks of high shear stresses and water holdup. Through corrosion risk assessment (CRA), the critical locations were narrowed down to four primary locations, which through direct inspection could provide the information necessary to estimate the overall pipeline condition. It is highlighted that without the In-line inspection (ILI) data, selection of inspection locations becomes problematic. However, carrying out a CRA in combination with dynamic flow modelling can build a more representative analysis and assist with effective engineering decision making. One of the available industry standard tools that can assist with demonstration of pipelines’ integrity requirement is an approach that integrates flow assurance with corrosion modelling known as Internal Corrosion Direct Assessment (ICDA). More specifically, an industry standard multiphase dynamic flow model (OLGA) with well-established corrosion models, CRA and engineering judgement have been employed to identify and prioritize inspection locations. A benefit of this work is the validation of predictions by both OLGA and the corrosion engineer in close adoption to the procedures of the NACE ICDA standard practice. Considerations from corrosion engineering aspect on modelling requirements and corrosion diagnosis will be presented, where the primary focus is on identification of hot spots and consequent inspection requirements in order to limit excavation activities and provide cost-effective solutions to the client.