CFD analyses to determine the performance of the thermal insulation system during cool-down of an Enhanced Vertical Deepwater Tree (EVDT) and a manifold for a subsea tie-in to an existing Floating Production Storage and Offloading (FPSO) are described in this paper. The produced fluid was assumed to be a multiphase mixture of gas and liquid with a gas volume fraction (GVF) of 14.05% for the EVDT and 73.46% for the manifold. The external environment was modeled as seawater at 4 °C, and a seawater current of 0.2 m/s was assumed. An Eulerian-Eulerian approach was used to solve the multiphase behavior of the produced fluid, in which one set of conservation equations is used for each phase at each mesh cell. Seawater flow patterns were solved with a single-phase, constant density solver with Boussinesq approximation. In general, it was found that cool-down times might be significantly different at some locations when the produced fluid is a multiphase fluid mixture as compared to the case where it is a single phase. Interestingly, Computation Fluid Dynamics (CFD) models predict a more rapid cool-down within the first 30 minutes of shutting down production as compared with traditional methods of determining cool-down times by modeling only heat diffusion with finite element techniques. Results from these analyses are a useful tool to determine the cool-down time that the produced fluid might remain above hydrate formation temperature prior to intervention. This has a direct implication on methanol system design and consumption. In addition, these results are an aid to determine which components of the equipment should have more insulation, as well as the impact of cold spots on cool-down times. Introduction One of the top priorities for oil and gas companies is flow assurance in the field. The main challenge of flow assurance is to overcome flow problems, which are generally associated with blockage of the flow path due to the formation of solid deposits or hydrates. These hydrates are crystals that form in flows where water and gas are present under a combination of temperature and pressure conditions. In general, it can be said that gas hydrate formation will occur at high-pressure and low-temperature conditions. Thus, there is a potential risk of gas hydrate formation as drilling and production operations expand into deepwater environments. Several works can be found in the literature that describe flow assurance challenges involving the prevention of solids formation [see, for example, Javora et al. (2005); Alboudwarej et al. (2006); Wang et al. (2006a, 2006b); Kopps et al. (2007); Harun and Watt (2009)]. Preventing the formation of solids may be accomplished by keeping the system in a thermodynamic state out of the regions in which the solids form. For example, hydrates do not usually form during normal operation in which the temperature of the fluids is above the formation temperature of solids. However, stagnant production fluids during shut-in operations will eventually reach seawater ambient temperature, thus potentially increasing the risk of hydrate formation. Therefore, special emphasis is placed on the effective control of heat losses in subsea equipment during shut-in and startup operations, because the ambient temperatures in deepwater are typically 40°F (approximately 4°C).

In mature fields, wells and pipelines are often oversized for the current operating conditions. This is because they have been primarily designed to handle early and midlife production, which may lead to slugging issues in later field life. The resulting flow fluctuations frequently lead to liquid handling problems caused by excessive liquid levels and pressure surges in the first stage separator. This can be an important source of downtime due to facility trips and deferment from sub-optimal facility operations. Furthermore, slugs travelling through topside piping can cause integrity issues when they impact bends.In flowline-riser systems, riser-induced slugging can lead to large slugs, especially in deepwater systems. These can usually not be contained in a platform-based separator. In such cases gas lift and conventional choking are often used to mitigate slugging. These two methods have drawbacks, however. For gas lift a source of compressed lift gas must be connected to the riser base and the volumes required to mitigate slugging may cause constraints in gas handling. Conventional choking leads to production deferment due to the backpressure imposed by a partially closed choke.In recent years "active" slug control methods have been developed to overcome these drawbacks. One such system is a relatively inexpensive solution developed by Shell Global Solutions* known as the Smart Choke. This system has been installed at several locations worldwide and has been proven to be very effective in stabilizing slugging in flowlines and risers. Here, the topside choke is actively controlled to mitigate riser-induced slugging and acts only if flow surges are observed, reducing the peak flow rate into the separator. Between slugs, the choke opens, reducing the imposed backpressure. Since flow fluctuations are reduced, a flowline can be operated at higher average flow rate as the topside facilities can be operated at higher throughputs without risking excessive separator liquid levels. Field data from case histories in the GOM, Malaysia and Nigeria indicate that production gains of 10% are often possible.This paper presents the modeling, implementation and the data obtained from operations of the Smart Choke implementation for a deepwater facility in Nigeria. The objective of the Smart Choke is to stabilize * Shell Global Solutions is a network of independent technology companies in the Shell Group. In this document, the expressions "Shell" or "Shell Global Solutions" are sometimes used for convenience where reference is made to these companies in general, or where no useful purpose is served by identifying a particular company.the flow from the riser and to reduce the gas lift requirement. A feasibility study was performed to analyze the slugging behavior of the pipeline and the impact of no control, gas lift and, the combination of gas lift and Smart Choke. Upon favorable modeling results, the Smart Choke was moved to the project stage and implemented. Field data are presented to demonstrate how the Smart Choke was able ...

As more subsea projects mature and with increasing understanding of operations involving subsea wells, the industry is constantly faced with the constraints and challenge posed by the requirements for metering, sampling, well testing and allocation. These challenges are even more pronounced in cases where flow assurance issues play a role especially for long tie-back systems. Current regulation in the Nigerian sector has yet to catch up with these developments and as such operators struggle to meet the requirements. A number of possible solution to the seeming problems or issues are under study, and with updated knowledge of the systems, it has become imperative to articulate and formulate strategies and philosophies for resolving or addressing the metering challenge for operations in Deepwater Nigeria. This article analyzes one of such solution in the application of subsea multiphase flow meters Introduction Subsea systems have evolved over the years, as a major solution to the technical and commercial challenge of harnessing reserves in the deepwater terrain. With the ability to extend tie-back distances, it affords a perfect means of achieving hub strategies allowing for continual development of reservoirs at great stepout distances. As stepout distances increase so does the challenge of delivering the hydrocarbon to the host facility. Flow assurance issues are key and often compounded by unwanted deposition such as hydrates, wax, scale and asphaltenes in the transportation and processing system components. This makes the task of measuring and quantifying the volumes of hydrocarbon products difficult. The traditional method is to measure these product quantities at the host, via test separators. The accuracy of the flowstream measurements is however a function of the stability of the system, requiring the introduction of artificial lifting systems (in most cases riserbase gaslift is employed). Operational experience with subsea production testing reveal that there are threshold rates required for stability. Below these threshold, serious system upsets such as slugging, impacts on the production system sometimes causing a shut down of the facility.