Asphaltene Flow Assurance Risk Mitigation through Emerging Approach of Inhibitor Numerical Modelling

This work was motivated for establishing a comprehensive evaluation method of asphaltene mitigation using inhibitor in an oil field that has a high risk of asphaltene precipitation in tubing. Application of asphaltene inhibitor is a typical counter measure and widely applied in many fields; however, most of the applications are temporary relief to mitigate problems. During an entire field life, the production operating condition has varied such as pressure decline, water cut and GOR increase, and so on. According to these variation, the inhibitor formulation that was once selected as the best effective one, its efficiency fades away. Then, another screening process is required to select alternative one and/or to modify the original formulation to adapt effectiveness to the new operating condition. This paper demonstrates a comprehensive estimation of its inhibiting efficiency during a whole field life by generating a numerical model based on results of asphaltene dispersant test (ADT) that was performed to experimentally select inhibitor for our one of oil field asset. The best asphaltene inhibitor IB-23 was selected through the two staged ADT from total nineteen samples because the IB-23 revealed highest inhibiting efficiency more than 80 % at 200 ppm concentration and maintained its efficiency more than 90 % even at 12.5 ppm. Based on this testing result, an emerging technique was applied to generate a numerical model to reproduce inhibiting efficiency. This special technique treated asphaltene inhibitor as pseudo-component defined using physical data that was available in public accessible material safety data sheet (MSDS). To date, any commercial software is not available for modelling of asphaltene inhibitor due to confidentiality for inhibitor’s physical data; however, our approach achieves to express the inhibiting efficiency as size-reduction of asphaltene precipitation envelope (APE) on thermodynamic plot. The model was generated using cubic-plus-association (CPA) EoS for fluid characterization, and the model validation was confirmed by comparing with the ADT data. Assuming natural depletion, the APEs were compared with variation of vertical lifting curves (VLC) in tubing. Two VLCs were assumed to represent early and late field conditions (i.e. high wellhead/reservoir pressures and depleted ones). The no-inhibitor case revealed precipitating risk existed over most of the tubing section. In contrast, the inhibitor dosed case could significantly reduce the risks in the early stage in particular. Even in the late stage, the risks could be minimized as the interception of VLC on the APE became shorter than the no-inhibitor case.