Two-phase gas-liquid (and vapor-liquid) flows occur in a variety of process equipment such as petroleum production facilities, condensers and reboilers, power systems and core cooling of nuclear power plants during emergency operation. In addition to these normal gravity applications, two-phase flows also occur in many space operations such as active thermal control systems, power cycles, propulsion devices, and storage and transfer of cryogenic fluids.For conditions of technological interest, there are a few major types of flow regimes observed for gas-liquid flows in pipes. Characteristics of these flow patterns and the conditions under which those flow patterns exist depends on the orientation of the pipe with respect to gravity. At low gas flow rates, a bubble flow pattern in which small gas bubbles are uniformly distributed in the liquid is obtained. Increasing the gas flow rate leads to slug flow. This flow pattern is characterized by large bullet shaped gas bubbles separated by liquid slugs. At even higher gas flow rates, a highly agitated churn flow is observed. Increasing the gas flow rate further leads to the annular flow regime in which the liquid moves along the pipe wall in a thin, wavy film and the gas flows in the core region.The above description applies only to two-phase flows in vertical pipes. In horizontal pipes, chum flow does not exist. At low gas flow rates, smooth and wavy stratified flows exist in such pipes.In the absence of gravity, there exist only three major flow patterns: bubble, slug, and annular (Figure 1). In microgravity, annular flows are obtained for a wide range of gas and liquid flow rates. Bubble and annular flow are the preferred flow pattern for the operation of two-phase systems in space. Slug flow is avoided, because vibrations caused by slugs result in unwanted accelerations. Therefore, it is important to be able to accurately predict the flow pattern which exists under given operating conditions of a two-phase flow system. Ever since the early work of Baker (19581, there have been attempts to predict the transitions between flow patterns for two-phase flows in pipes. Because of the large number of dimensionless groups (seven to nine) describing the phe-

The continuity and momentum equations for fully developed and spatially developing slug flows are established by considering the entire film zone as the control volume. They are used for the calculations of pressure gradient, slug frequency, liquid holdup in the film, flow pattern transition, slug dissipation, and slug tracking. Comparison with available experimental results shows that these equations correctly describe the slug dynamics in gas-liquid pipe flow. [S0195-0738(00)00701-9]

Hilly-terrain pipelines consist of interconnected horizontal, uphill and downhill sections. Slug flow experiences a transition from one state to another as the pipe inclination angle changes. Normally, slugs dissipate if the upward inclination becomes smaller or the downward inclination becomes larger, and slug generation occurs vice versa. Appropriate prediction of the slug characteristics is crucial for the design of pipeline and downstream facilities. In this study, slug dissipation and generation in a valley pipeline configuration (horizontal-downhill-uphill-horizontal) were modeled by use of the method proposed by Zhang et al. The method was developed from the unsteady continuity and momentum equations for two-phase slug flow by considering the entire film zone as the control volume. Computed results are compared with experimental measurements at different air-mineral oil flow rate combinations. Good agreement is observed for the change of slug body length to slug unit length ratio.

Flowline depressurization ("blowdown") is an effective flow assurance operation to protect flowlines from hydrate formation for unplanned or extended shutdowns. Both numerical simulations and field experience have shown that blowdown is generally feasible for uphill flowlines over a wide range of gas-liquid ratios (GOR), water cuts and operating conditions. It is often assumed, however, that blowdown is not feasible for downhill-sloping flowlines, where liquid accumulated in the riser cannot be fully discharged to reduce the flowline pressure. OLGA calculations presented here indicate that blowdown is in fact successful for downhill flowlines, although in a more narrow operating envelope than for monotonic uphill flowlines. Requirements for blowdown feasibility are identified over a range of governing parameters, including fluid GOR and water cut, and flowline/riser geometry (i.e. diameter, water depth, offset length, inclination). Based on this generalized analysis, operating strategies to increase blowdown effectiveness for downhill flowlines are evaluated. The impact of terrain slugging on blowdown feasibility, which generally accompanies flowlines with downhill inclination, is also evaluated. Reasonably good agreement of computational results with available deepwater field data for blowdown is observed. Introduction System design and op erating procedures for subsea oil systems are usually developed to protect flowlines from hydrate plugging, because remediation of hydrate plugs is very costly and may require weeks to even months to melt a plug. Hence, the fluid temperature in the flowline is maintained above the hydrate dissociation temperature at any operating pressure. Steady state and transient thermal-hydraulics analysis is employed to determine insulation requirements to ensure operation outside the hydrate region during normal operation, as well as start-up and shut-down. For start-up operations in which the flowline or riser enter the hydrate region, temporary injection of a hydrate inhibitor (e.g. methanol or LDHI) is required. Alternatively, for dual flowline systems, circulation of a heated dry fluid (e.g. dead oil or diesel) may be used to preheat the flowlines. To protect the flowline from hydrate formation during shut-down, the elapsed time must be carefully monitored to not exceed cooldown time of the flowline and riser to hydrate formation conditions. For some shutdown scenarios, additional operations are needed to secure the flowline against hydrate formation. For example, interrupted start-up may occur before system warmup has been achieved, or the shut-down time may exceed the flowline cooldown time, typically 8-12 hours. In these extended shutdown situations, flowline depressurization, or blowdown, can be the "last resort" to prevent hydrate formation. Alternatively, circulation of dry oil may be used to remove wet fluids in dual flowline systems. However, dryoiling is an inherently "active" operation requiring topsides power availability and sufficient oil storage. Further, flowlines are temporarily pressurized by dry-oiling (due to the riser hydrostatic head), which may increase the hydrate risk. In contrast, the blowdown operation is a "passive" operation to reduce the flowline pressure to below the hydrate dissociation pressure at ambient seabed conditions. As a result, even if the blowdown is only partially effective, operations can "buy time" for troubleshooting of the shutdown cause. Additionally, flowline depressurization - if effective - can be used as a means of hydrate remediation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractBonga -the first Deepwater development in Nigeriacommenced production in Q4 2005. At an early stage of the project, flow assurance was identified as a key factor for successful development, noting: (i) complexities of the subsea network, including local downhill flow, (ii) logistical challenges of a new Deepwater basin, and (iii) reservoir fluids' propensity for solids formation, including additional risks posed by full-field waterflood.This paper discusses the key elements of the Bonga flow assurance strategy and its implementation in design and operations, with particular focus on the flow assurance performance of the subsea system during initial start-up. Comparisons of field data with analysis predictions include: (i) steady-state thermal-hydraulic performance, (ii) system thermal response during cold start-up, (iii) cooldown performance of subsea hardware and flowlines, (iv) system blowdown effectiveness, including the effect of riser gas-lift and (v) terrain slugging severity and gas-lift requirements.