Impact of Electrically-Heated Systems on The Operation of Deep Water Subsea Oil Flowlines

Abstract

Abstract Electrically-heated flowlines offer a fundamentally different and simpler approach to managing hydrates in deep water subsea oil flowlines, when compared with conventional solutions. Current operating and design strategies used to manage hydrates are compared with strategies that could be adopted in fields having electrically-heated flowlines. The paper also identifies additional opportunities to handle other flow assurance challenges. Introduction The process of "flow assurance" is a well recognized critical element in the design and operation of subsea systems throughout their entire life-cycle. "Subsea flow assurance" can be defined as the integrated management of solids (hydrates, paraffins, asphaltenes, scale and sand), fluid properties, corrosion potential, and operating procedures required to sustain production in a dynamic, multi-phase subsea environment. Flow assurance design and operation become challenging in deep water due to a combination of low temperatures, high internal hydrostaic pressures and economic drivers for long offsets and high availability.1,2,3,4 Relative to hydrates, paraffins and operating practice, the solutions for gas and oil systems tend to be different. For relatively dry gas systems, the dominant concern usually is hydrates. Continuous inhibition with either methanol or mono-ethylene-glycol, is a common and robust solution. The systems can be operated on a once-through basis (normal approach with methanol) or the inhibitor can be reclaimed (normal approach with glycol). Low-dosage hydrate inhibitors (LDI's) are emerging; however, no field has yet to be developed with LDI's as a base case. If a hydrate plug forms, remediation is by line depressurization. For oil systems in deep water, both hydrates and paraffins are at issue. In the Gulf of Mexico (GOM), a strategy, often termed the "blowdown strategy", is commonly used. The strategy relies on conservation of heat (through insulation) to remain outside of the hydrate and paraffin deposition regions during steady state operation. During start-ups and shutdowns, a combination of activities including inhibition, depressurization (blowdown) and fluid displacement are performed. Wax is removed by pigging. This approach has been used successfully at several GOM fields including Angus, Macaroni, Tahoe and Troika. It is also the base case approach in many other GOM subsea oil fields. The strategy is effective, but depends on successful execution of relatively complex operational sequences. If a hydrate plug forms, it is necessary to depressure the line (usually below 400 psi) and wait for the plug to disassociate (which could take a very long time in a well-insulated system). For intermediate systems (relatively high fractions of liquid hydrocarbons and/or water, in gas), the design solutions are very site-specific. Although not a deep water system, Britannia's5 use of a hot-water bundle illustrates the diversity of possible approaches. For deep water oil systems, the hydrate and wax issues could be managed by adding heat to the system. Hot water has already been mentioned. Exothermic chemical processes are used by Petrobras for remediation of wax deposits.6 Electrical heating is another technology that is rapidly maturing. It also has the potential to be cost competitive in deep water applications.