Developing Hydrate Monitoring and Early Warning Systems
- Bahman Tohidi (Heriot-Watt University) | Antonin Chapoy (HW University) | Jinhai Yang (Heriot-Watt University) | Farid Ahmadloo (Heriot-Watt University) | Ivan Valko (Heriot-Watt University) | Zahidah Md. Zain (Petronas Reserach Sdn Bhd)
- Document ID
- Offshore Technology Conference
- Offshore Technology Conference, 5-8 May, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2008. Offshore Technology Conference
- 4.3.4 Scale, 5.9.1 Gas Hydrates, 4.1.3 Dehydration, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 5.2.2 Fluid Modeling, Equations of State, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 4.2.3 Materials and Corrosion, 4.3 Flow Assurance, 4.3.3 Aspaltenes, 7.1.8 Asset Integrity, 4.3.1 Hydrates, 5.2 Reservoir Fluid Dynamics, 4.2 Pipelines, Flowlines and Risers
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A major challenge in offshore development is to ensure unimpeded flow of hydrocarbons. Managing solids such as hydrates is the key to the viability of developing a deepwater prospect. Common methods to prevent and reduce hydrate risks are generally based on injection of thermodynamic inhibitors to prevent hydrate formation or use of kinetic hydrate inhibitors to sufficiently delay hydrate nucleation/growth. Currently, the amount of inhibitor required is either calculated and/or determined based on lab experiments. The amount of inhibitor depends on various parameters, including, water cut, inhibitor loss to hydrocarbon phases, aqueous and non-aqueous fluid compositions, operating conditions. Generally a safety factor is considered and the resulting inhibitor is injected upstream without much downstream measurements. Despite the usual safety margins, gas hydrates are formed which could result in serious operational and safety concerns. This is mainly due to changes in the system conditions (e.g., rates and water cut) and/or malfunction of one of the equipment. In most cases, the amount of inhibitor is more than what is necessary and is not adjusted with seasonal changes, affecting CAPEX/OPEX.
As a result of a joint industry project several novel techniques, based on downstream and online measurements have been developed, for:
- Monitoring the hydrate safety margin to optimise inhibitor injection rates. The system determines the amount of inhibitor in the aqueous phase and the degree of inhibition they can offer.
- Detecting the initial hydrate formation, as an early warning system against hydrate blockage. The system detects the changes in the system due to hydrate formation with the aim of giving the operator enough time to prevent a blockage.
The main advantages of the above techniques are minimising the amount of inhibitor required and preventing pipeline blockages due to hydrates, hence the cost of inhibitor, impact on the environment, cost of remedial actions and deferred production. A number of techniques have been investigated during this project with some techniques selected for prototype development. The developed prototypes have been tested. In this presentation, an update on the latest results of this new approach in flow assurance control is presented.
The past decade has witnessed dramatic changes in the oil and gas industry with the advent of deepwater exploration and production. A major challenge in deep water field development is to ensure unimpeded flow of hydrocarbons to the host platform or processing facilities. Managing solids such as hydrate, waxes, asphaltene and scale is the key to the viability of developing a deepwater prospect.
The oil industry is facing a flow assurance issue with hydrate deposits in pipelines where hydrate often forms at inaccessible locations. One of the problems other than blockage is the movement of the hydrate plugs in the pipeline at high velocity which can cause rupture in the pipeline. Any blockage in an oil/gas pipeline due to hydrate is a serious threat to the economics of the operations and also personnel safety.
The conventional ways to prevent and reduce hydrate risks in transfer line and process facilities is to remove one of the elements favouring hydrate formation. For example, thermal insulation and external heating techniques are used to remove the low temperature element. Water can be removed by dehydration of the natural gas using glycol system and lowering the operating pressure can reduce the tendency for hydrate to form in the production system. However, these conventional techniques may not be feasible for some fields especially in offshore and deepwater environment due to space limitation and high insulation or heating cost. The deepwater insulation costs are reported typically US$1 million per km of flowline (Sloan, 1998).
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