The Effect of Cement Heat of Hydration on the Maximum Annular Temperature of Oil and Gas Wells
- R.L. Dillenbeck (BJ Services Co.) | T. Heinold (BJ Services Co.) | M.J. Rogers (BJ Services Co.) | I.G. Mombourquette (PROMORE Engineering Inc., Div. of Core Labs Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- December 2003
- Document Type
- Journal Paper
- 284 - 292
- 2003. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 1.14.3 Cement Formulation (Chemistry, Properties), 1.10 Drilling Equipment, 4.3.4 Scale, 4.3.1 Hydrates, 1.14 Casing and Cementing, 2.2.2 Perforating, 2.2.3 Fluid Loss Control, 1.6 Drilling Operations
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Recent advances in electronics technology have made it possible to monitor and record real-time annular temperatures in operational wells, both during and after primary cementing. The developments have allowed operators to record the entire annular-temperature history of their wells, including the critical period when cement hydration occurs. The ability to record these actual temperatures can significantly impact the oilfield cementing industry in several ways. Most significantly, currently accepted practice within the industry is to test certain critical aspects of set cement, such as compressive and tensile strength, at the bottomhole static temperature (BHST). If the short-term maximum annular temperature is significantly different from the later BHST of the well, laboratory tests run on cement at a steady BHST may prove to be inaccurate when based on the actual temperature encountered by a cement slurry downhole. Also of concern is the fact that the magnitude of any temperature change after the initial set may have profound effects on the induced stress in the cement sheath as well as on the casing and formation because the maximum temperature spike from hydrating cement may not occur until after the cement has achieved an initial set.
On the basis of actual field measurements of annular temperatures, this paper details how the variable factors of individual heat of hydration (HOH), relative annular geometry, and final BHST interact to produce short-term maximum temperatures in the cement sheath. In some instances, these maximum temperatures can vary significantly from the stabilized BHST in a well. The actual annular-temperature data were recovered from wells in both North and South America and include shallow and deep well applications.
As recent technological advances have pushed the exploration for oil and gas reserves to more extreme locations and conditions, service companies have had to re-evaluate many long-held notions with respect to how and under what conditions well cementing compositions should be tested. One prime example would be deepwater exploration. As several authors1-3 have noted, seafloor temperatures near or even slightly less than the freezing point of fresh water are not uncommon conditions under which cement must be successfully placed and hydrated. In other extreme onshore applications at high latitudes, permafrost can expose cement systems to very low temperatures, under which the cement is expected to hydrate. At the opposite end of the spectrum, high-pressure/high-temperature (HP/HT) drilling in various locations throughout the world pushes the upper temperature extremes at which cement must be carefully placed and hydrated.
Concurrent with placing annular sealing cement in ever more challenging conditions, the oil and gas industry also has begun to examine more closely both the short- and long-term mechanical properties of annular sealants and the effect these properties have on long-term annular isolation.4 To better test the mechanical properties of cement under well conditions, the cement must typically be cured, or hydrated, for the appropriate amount of time under temperature and pressure conditions as close as possible to the downhole conditions in the well. If the cement system is not hydrated at the correct temperature(s), the resulting mechanicalproperties tests may yield results that are inconsistent with the properties developed by the cement in the actual well. Further, the actual induced stresses in a set annular cement sheath have been shown to be influenced by short-term changes in wellbore temperatures. 4,5 As Romero and Loizzo6 have noted, "one could consider that the cement has set once the temperature is maximum in the wellbore." Given the annular-temperature reduction that can occur after cement hydration, it would seem logical that if the change is great enough, it could induce significant stresses into the recently set cement.
Finally, new advances in completions technology have made possible certain tools, such as external casing perforating guns that must be sealed in the cemented annulus of a well using such technology. While cementing these nonsymmetrical annuli can be challenging, it can be accomplished successfully.7 However, the tools that are left cemented into the annulus obviously must be subjected to the same conditions as the cement that hydrates around them in the annulus. Because most tools, gauges, and/or sensors used in oil and gas wells have certain design limits for time at temperature and pressure, it can be critical to know what conditions these annular devices are being exposed to at a given point in time to ensure correct operation.
Historically, most performance testing for set cement has been undertaken at or very near the BHST at the depth the cement is placed. Typically, cement curing chambers that hydrate the cement and hold it for given amounts of time under downhole conditions (before testing) will be slowly heated up (or cooled down for cold BHSTs) from a point near the anticipated bottomhole circulating temperature (BHCT) to the BHST. The BHST will then be held until the end of the curing time, at which point the appropriate testing of the cement's mechanical properties may be performed.
Likewise, many downhole tools and other mechanisms may be tested for extended periods at the anticipated BHST to determine their anticipated performance level in a given well.
Fortunately, it has now generally been recognized that because of the exothermic nature of Portland cement, hydration can inject significant amounts of thermal energy into a wellbore once it begins.6 Measurements in the test wells, as well as certain numerical simulator models, have suggested that early in the life of a well, this heat flux can drive the annular temperature to greater than the stabilized BHST for some time.3,6 Just how significant the annular temperature increase would be appears to be dependent upon several factors, not the least of which would be the mass of hydrating cement per unit of well depth, the slurry temperature at the start of hydration, and the composition of the actual cementing system used.
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