Steady-state and transient thermal performance of subsea hardware

The thermal performance of subsea hardware is of ultimate importance to the economic development and reliable operation of deepwater subsea oil and gas systems because of the potential for hydrate formation. Results of numerical calculations are presented on the thermal performance of subsea equipment such as wellheads, tubing and flowline jumpers, and flowline field joints. In contrast to previous published studies on the thermal performance of insulated subsea wellbores and flowlines, this paper addresses the thermal performance of the subsea equipment that can provide weak thermal links for the subsea system. Although subsea insulated flowlines can eliminate or reduce the risk of hydrate formation during steady-state production, they may not provide sufficient cooldown time before hydrates are formed during an emergency shutdown. Subsea wellheads, pipe field joints, manifold jumpers, and flowline and tubing jumpers are very difficult to insulate effectively. As a result, these pieces of equipment exhibit faster cooldown to hydrate-formation temperature than does either the wellbore or the flowline. A two-dimensional (2D), general-purpose, finite-element, partial-differential equation solver was used to analyze the steady-state and transient thermal behavior at different cross sections of the subsea tree. In contrast to the intuitive common belief that a subsea-tree cooldown time to hydrate-formation temperature is on the order of several hours, a cooldown time less than 2 hours was determined after a system shutdown. Steady-state analysis of a flowline field joint indicates that the joint degrades the flowline thermal performance, causing up to a 20% increase in the flowline overall heat-transfer coefficient. To our knowledge, such results have not yet been presented in the literature. This paper presents a new method for predicting pressure profiles in oil and gas wells. The method combines mechanistic flow-pattern transition criteria with physical models for pressure-loss and liquid-holdup calculations for each of the flow patterns considered. Past published methods relied heavily on empirical fit of limited field data. As a result, they are inaccurate when used outside the range of data upon which they are based. In contrast, the new method is universally applicable to all types of wells under all operating scenarios because it is based on fundamental physics rather than the curve-fit of field data. Its prediction performance has been demonstrated by extensive comparison to field data from a variety of wells.