Prediction of Cool Down Times and Designing of Insulation for Subsea Production Equipment (2004)

Abstract In long flow lines, steady state heat loss drives the design of the thermal insulation to prevent hydrate formation and wax deposition. In subsea production equipment, such as trees, manifolds, and jumpers, transient cooling caused by an interruption in well flow drives the design and thickness of the insulation system. Thermal insulation is necessary in these systems to keep the produced fluid above the hydrate formation temperature long enough for the operator to either introduce hydrate inhibitors or until flow can be reestablished. Typically operators require eight to twelve hours above the hydrate formation temperature. Trees and other subsea production equipment are of complex shapes, and therefore, require complex analysis to predict cool down time, and determine the thickness of insulation required to meet cool down requirements. Finite Element Analysis (FEA) is typically used to predict cool down times, determine required insulation thickness, and location of insulation. Often cool down testing is performed to determine the accuracy of the FEA model. Also, simulated service testing can be done on actual equipment to determine locations of excessive heat loss, and structural elements that may act as heat sinks, affecting cool down time. In this investigation, the FEA results are compared to cool down measurements from a full-scale simulated service test. Based on the results of these tests combined with the thermal analysis, thermal insulation thickness and location in subsea production equipment can be determined. Introduction Statement of Problem As drilling and production operations expand into deepwater environments, operators need to consider the potential risk of gas hydrate formation in well bores, subsea pipelines and subsea equipment during both drilling and production operations1. Complex geometries, such as subsea trees and associated piping, well-to-manifold jumper lines, manifolds, manifold-to-sled jumpers, flow line termination sleds require unique approaches to analysis, design, and location of insulation for hydrate prevention during cool down. Hydrates Gas hydrates are ice-like solids that form from gas and water under combinations of high pressure and moderately low temperatures. Alkane hydrates in the form of crystalline methane hydrate can form at temperatures as high as 21 °C (70 °F) at pressures of 300 bars (4,300 psi)2. This is illustrated in Figure 1. Figure 1. Phase diagram showing conditions under which hydrates will form (Available in full paper) Hydrates can form at conditions to the left of the curve shown in Figure 1. At conditions to the right of this curve, hydrates will not form. Hydrate formation conditions depend on gas composition, primarily the presence of low-molecular weight hydrocarbons such as methane, ethane, propane, iso-butane and normal butane and the water salinity. The risk of forming hydrates is greatest when the well is cold. This condition usually occurs during a production start-up or while the well is shut down following a period of flow. Hydrates can also form while the well is flowing if the well temperature and pressure present the right conditions. For example, in a flowing subsea well at the combination of high flowing temperature and typical flowing pressure (Example: 60 °C (140° F) and 250 bars (3,625 psi) in Figure 1), hydrate formation is not an issue.