Trapped fluid commonly occurs in subsea completed wells when casing annuli attains a closed volume; for example, a subsea wellhead set and cement top inside the previous casing shoe. When the well is placed on production and wellhead temperature increases, the trapped fluid, usually drilling mud and spacer, expands. This thermal expansion significantly increases the annular pressure. Depending on the initial wellhead conditions, the trapped fluid's temperature could increase in excess of 83ºC (150º F) over ambient conditions. Laboratory testing indicates that trapped water- or synthetic oil-based fluids can increase in pressure (greater than 69 MPa or 10,000 psi) well above the casing collapse pressure if the well experiences such a differential temperature cycle. An effective solution offered in previous literature is the incorporation of a compressible spacer in the cementing process. The compressible spacer is trapped in the closed annulus and can greatly reduce the pressure buildup if fluid expansion occurs. Deepwater operators have used this solution in a casual manner because the margin for error is somewhat large. However, in shallower subsea completed wells (less than 300m or 1,000 ft water depth), the margin of error is greatly reduced. This reduction motivates the need to find the optimal compressible spacer volume based on lower final hydrostatic pressures and appropriate volume to compensate for fluid expansion. Operationally, finding these optimal volumes helps reduce the chance of a kick condition or compressible fluid being circulated into the riser system. This paper presents a method for calculating the optimal amount of compressible spacer to be trapped in a well's annulus. The calculations consider the expansion of the trapped fluid based on annular volume and fluid type(s). The paper also presents previously published data on various water and synthetic oil-based fluids and an example of the calculations in well conditions for an east-coast Canadian subsea well.