Robert L. Dillenbeck

The Effect of Cement Heat of Hydration on the Maximum Annular Temperature of Oil and Gas Wells

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.

Highly Relaxed Fluid Loss, Surfactant Enhanced Cement Improves Results on Deep Gas Wells

While it is certainly true that advances in technology make it possible to drill and complete many wells faster and cheaper than ever before, it is also possible to make incorrect and costly blanket assumptions that increased technology will always yield enhanced results. One such area of technology is in fluid loss control of primary well cementing. By controlling cement slurry fluid loss, casing strings can be cemented at depths, temperatures, and difficult bottom hole conditions rarely seen twenty and thirty years ago. Today, it is not uncommon for operators to routinely utilize primary cement slurries formulated to possess API fluid losses of 50 cc or less, regardless of where, or in many cases how, the well is drilled. While this kind of fluid loss control is without a doubt necessary in many areas of the world, the fact remains that cement fluid loss control additives are as a group, one of the most expensive cement additives used. The authors detail in this paper a unique, surfactant enhanced, relaxed fluid loss cement design and placement process used to successfully cement deep gas wells in the Anadarko basin of Oklahoma and Texas Panhandle. Many of the wells have final production casings or liners set in the 18,000 to 20,000 ft. range. While the authors caution that the systems and techniques presented may not be applicable to all deep wells, the general drilling history of the subject wells is examined to help detail how and why the systems work. By analyzing the information presented, it should be possible for operators to identify potential candidate wells of their own which might benefit from similar systems. An analysis of slurry/spacer design as well as placement criteria is examined in this paper. Then an economic analysis detailing where and how the cost savings are realized is reviewed. Finally, the results of the primary cement jobs are reviewed showing both enhanced bonding and hydraulic isolation, as well as significantly decreased remedial squeeze requirements.