Abstract

The objective of this paper is to discuss a methodology used to assess the erosion risk of well equipment in an HPHT gas field offshore Egypt. Raven is an offshore subsea HPHT wet gas field located in the West Nile Delta region. During the well design phase a few challenges were faced with the erosion assessment of the Sub-Surface Safety Valve (SSSV).

A preliminary erosion study assuming dry gas with no liquids in the tubing showed excessive erosion rates and the potential outcome of having to choke back production. The analysis was performed using different erosion models and empirical formulas and all gave comparable results.

In high rate gas wells the worst case for erosion is in dry gas conditions due to the direct impingement of the produced solids particles with the metal, as there is no liquid to provide ‘cushion’ effect. The metal loss is greatly reduced if there is a liquid film present on the internal surface of the completion equipment, effectively dampening the impact energy of the solid particles with the metal. Produced formation water can help mitigate the erosion rate however it is anticipated that it will be produced only late in field life. The worst case for erosion is experienced at the end-of-plateau conditions, years before water breakthrough.

The next step of the study was then to estimate the amount of condensate dropout in the tubing as a mean of controlling the metal loss. The relatively low expected Condensate Gas Ratio (CGR) of the reservoir fluid implied that the predominant flow regime within the tubing would either be mist or annular flow, but to determine the rate of metal loss it was necessary to quantify the relative velocities of the liquid and gas phases. A black oil retrograde condensate PVT model was generated from a tuned Equation of State (EoS) model and was used in a nodal analysis tool to estimate liquid dropout across the tubing length. The erosion assessment was re-evaluated this time considering the liquid dropout at the SSSV (process conditions) showing an acceptable erosion rate.

This approach can be applied on many high rate gas fields where erosion rate is a threat that could impact the production rates. In our case, demonstrating the presence and quantifying the amount of liquid film in the tubing and the positive effect on reducing erosion, helped define appropriate operating envelopes to deliver the required well potentials.

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