Flow-Assurance Strategy Manages Subsea Asset Without Continuous MEG Injection
Authors: Feder Judy 
Published: August 2020

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195784, “A New Flow-Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset,” by Stephan Hatscher, SPE, and Luis Ugueto, Wintershall Norge, prepared for the 2019 SPE Offshore Europe Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed.
The Vega field on the Norwegian Continental Shelf has been producing successfully using continuous monoethylene glycol (MEG) injection, topped with means of corrosion inhibition. A topside reclamation process allows reuse of MEG but limits the possibilities of producing saline water. The complete paper presents a discussion of a feasibility study of a new flow-assurance and -integrity philosophy to manage wells without continuous MEG injection. The paper describes options for hydrate and integrity management and the required modifications to both subsea and topside facilities to enable an operational philosophy change.
Current Subsea Flow-Assurance Approaches
Gas-hydrate formation in wet gas flowlines is considered one of the primary challenges seen in subsea assets. Its mitigation requires considerable capital expense and often significant operating expense (OPEX) over field life. Although the thermodynamic stability of the ice-like structures is well understood, the same is not the case for the kinetics of their formation or the dispersion in multiphase systems, which might be a crucial aspect in hydrate plug formation. Traditionally, the approach to hydrate mitigation has been to keep the system outside the hydrate-formation region by various means, including the following:
Insulation of flowlines or direct heating possibilities
Depressurization on shutdown
Hydrate inhibition by thermodynamic or low-dosage hydrate inhibitors
Subsea separation and drying of gas
For long multiphase flowlines, options are limited. Insulation or direct heating often is uneconomical. Depressurization on shutdown requires significant storage space on a host facility for liquids and leads to massive volumes of flared gas. Subsea separation and gas drying are not yet fully mature, so use of hydrate inhibitors is common.
Hydrate inhibitors can be classified as either thermodynamic or kinetic inhibitors. The latter are also called low-dosage hydrate inhibitors (LDHI) because of the lower concentration required. The main advantage of thermodynamic inhibitors is that they shift the hydrate curve to fully protect the system, whereas the kinetic inhibitors tend to wear off after time, leaving the systems un- or underprotected. However, their use often allows for infrastructure reduction and simplified production operations.
The most typical thermodynamic inhibitors are based on salts (as from the formation water) or alcohols such as methanol, ethanol, or glycols. The advantage of the latter is that their separation from water is technically viable, so they can be used in a recycle, or closed-loop, system, which can only function well in systems free of salinity or with limited saline formation water ingress.