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Challenging the Need for Dual Gas Production Flowline Systems Using Emerging Hydrate Remediation Intervention Technology

[+] Author Affiliations
Henry Sheil, Peter Young

Peritus International Pty Ltd., Perth, WA, Australia

Paper No. OMAE2011-49191, pp. 159-172; 14 pages
doi:10.1115/OMAE2011-49191
From:
  • ASME 2011 30th International Conference on Ocean, Offshore and Arctic Engineering
  • Volume 1: Offshore Technology; Polar and Arctic Sciences and Technology
  • Rotterdam, The Netherlands, June 19–24, 2011
  • ISBN: 978-0-7918-4433-5
  • Copyright © 2011 by ASME

abstract

Gas production flowlines are presenting flow assurance challenges in hydrate management resulting from low ambient seawater temperatures in an increasing number of deepwater developments. During operation the equilibrium hydrate temperature of the produced fluid may be above the minimum seabed temperature, and hence there is a risk of hydrate blockage in the subsea system should the hydrate inhibition system fail. The continuous injection of MEG, with little or no insulation of the subsea system, is a common hydrate mitigation strategy for a gas production system. If insufficient inhibitor is injected there is a risk of hydrates forming and potential blockage of the pipeline in parts of the field. The industry-preferred approach for hydrate blockage remediation is Dual Sided Depressurisation (DSD). The objective is to depressurise the flowline to below hydrate onset conditions, allowing hydrate dissociation and safely disposing of the gas inventory. This is typically performed by one of two methods; installation of a dual flowline system for facility based depressurisation (with CAPEX implications); or a Mobile Offshore Drilling Unit (MODU) can be connected to an appropriate point upstream of the blockage to allow simultaneous depressurisation at the MODU and the facility (with OPEX implications). It is recognised that either method incurs significant costs. Typically the cost and time uncertainties of bringing in a MODU to solve these production stoppages is unattractive. Consequently subsea gas developments have often incurred the increased CAPEX of providing dual flowlines to permit DSD from the facility. An optimisation of the MODU-based intervention method is the subject of this paper. The feasibility of using a “lightweight” intervention vessel (for example an Offshore Support Vessel) in place of the MODU to depressurise the flowline is discussed. This paper discusses hydrate remediation difficulties and case studies; presents emerging hydrate remediation methods and briefly introduces vessel requirements. In discussing this optimisation, this paper also presents an introduction to hydrate remediation theory, some practical challenges, case studies and vessel requirements. The study concluded: • Significant CAPEX reductions may be achieved by adopting the outlined strategy; namely avoiding dual flowline infrastructure, and ensuring a reduced response time and day rate for any hydrate remediation operations to be performed. • For this strategy to be adopted cost effectively, pre-engineering, along with suitable contractual arrangements, are required to make the necessary equipment and personnel resources readily available should a hydrate blockage occur. For assets in remote locations, e.g. Australia, making the resources available is a significant challenge. • Flowline system access for depressurisation may be achieved by two methods; via the subsea Christmas tree or via suitably located fluid injection/vent access point(s).

Copyright © 2011 by ASME

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