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 83°C (150°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. Annular Pressure Buildup Definition Annular pressure buildup (APB) is a phenomenon that has been recognized in the oil and gas industry for many years. APB is the pressure generated by thermal expansion of trapped fluids as they are heated.1 When wellbore fluids heat up and expand in a closed system, the expansion causes high induced pressures. Most land and many offshore locations may be able to bleed this pressure through surface-accessible wellhead equipment. In subsea completions, the primary annulus between the tubing and production casing (the "A" annulus) may be the only accessible annulus. Consequently, bleeding of the outer annuli ("B", "C", etc.) may not be possible. Therefore, when the risk of subsea APB exists, well designers should give serious consideration to appropriate mitigation as part of the fundamental well design. When a well experiences APB, two conditions are known to be present. First, a sealed annulus (or annuli) must exist. A sealed annulus is a common occurrence and is usually associated with the cementing process. When a formation must be isolated from the rest of the well, cement is circulated above the formation and the top of cement (TOC) is frequently inside the annulus of the previous casing. Second, a temperature increase must occur. The trapped fluid will be heated by the drilling and production operations. Most casing strings and displacement fluids are installed at or slightly below static temperature condition. When the fluid is heated by production, it expands and can produce a substantial pressure increase, which can be compounded if more than one annulus is sealed. Cold sea-bed located wells (such as deepwater or arctic locations) can be vulnerable to APB because of the cold seafloor temperatures at installation, in contrast to elevated production temperatures.
said he thought the diagrams (Figs. 5, Gand 7, pp. 12, 16 and 19) had not been sufficient,ly explained. I n each case the lines generally represented pumpiug a t a uniform rate. That, of course, was necessary to obtain a line which represented the actual power or force of the spring.In the case of Rickmansworth (Fig. 7), at the lower half, the line coming down showed an increase in the rate of pumping. The pumping was generally carried on at the rate of 15,000 gallons, and then it increased to over 21,000 gallons an hour. The diagram showed the value of increasing the depth and the size of the bore-hole. At Wokingham, the spring continued to fall for a number of hours : in ten hours it had fallen 42 feet, then, on ceasing t o pump, it rose for many hours, but not to its original level. That showed that the water had great difficulty in reaching the borehole, due to the fact that it had to travel a great distance underground. The water was coming on as fast as it could, but it could not get through in consequence of the enormous pressure of the Tertiary beds overhead. The thing t o be sought for in chalkwells was the presence of flints. Wherever there were flints in abundance there was water in abundance, and where there were no flints there was little water. He had often had the idea that the water itself tended to create the flint in chalk, but how far that theory was to be supported by chemists and geologists he did not know. What happened was this :-In flint beds in the Chalk there was a quantity of sand ; and on pumping, that sand gradually worked out, the water dissolving the Chalk and leaving spaces between the flints, through which it could readily travel. In the case of the Leatherhead well, a t t h e bottom there was a continuous bed of flints, hence a vast underground reservoir of water. It was Minutes of the Proceedings of the Institution of Civil Engineers 1887.90:40-90.
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