Wellbore Design With Reduced Clearance Between Casing Strings

Abstract

Wellbore Design With Reduced Clearance Between Casing Strings J.W. Barker SPE/IADC Member Abstract In the past the industry relied on general rules-of-thumb to determine the clearance between casing strings. In today's difficult cost environment all traditional design factors should be challenged and an engineered solution determined. When a detailed engineering analysis is performed, these general rules-of-thumb are often found to be conservative or out-of-date. With recent technological improvements the limiting factor in the wellbore and casing design process is often the acceptable clearance between casing strings. As a result, detailed engineering analysis is needed to determine the clearance required between casing strings for the particular application. With the optimum clearance between casing strings designed for each situation, well casing sizes can often be reduced or additional casing strings can be accommodated in the well design. This concept is important today as the industry is drilling more wells with the combined challenges of high pressure, high mud weight, high temperature, and deep depths. Such wells often require more casing strings to reach total depth yet designers are limited by existing rig equipment sizes and capabilities. Introduction Many years ago the industry developed general rules-of-thumb for clearance requirements between casing strings and drilled holes. These rules-of-thumb resulted in commonly used casing and bit size combinations. Generally, at least 0.6- to 0.8-in. of radial clearance between a casing string coupling and the design inside diameter of the next larger casing string were recommended. A hole diameter 3-in. larger than the casing outside diameter (OD) was recommended for ideal cementing. These general rules-of-thumb did not differentiate between applications depending on depth, mud properties, etc. Pressure surges from running casing strings were not critical design issues since there was usually a large margin between formation fracture pressure and formation pore pressure. In today's economic environment. well designers cannot afford to leave excessive margins between formation fracture pressure and formation pore pressure even on routine wells. More difficult wells are also being drilled that are deeper and have higher formation pressures. Drilling problems are increasingly encountered which require surge pressures be maintained in very narrow limits while running and cementing as many as six casing strings in a well. Each additional casing string adds significant cost and complicates the casing size selection process. Typically the well design process begins with the selection of the desired size production tubing and moves uphole. With the very high cost of deep, high pressure wells, larger size tubing strings capable of conducting economical flow rates are desired. Production casing sizes greater than 9 5/8-in. OD are often required to accommodate tubing sizes as large as 7-in. OD or large dual subsea completions. The large production tubing size constrains the design at the bottom of the well and available blowout preventers (BOP's) will constrain the surface casing size. High pressure BOP's larger than 18 3/4- to 20-in. inside diameter (ID) are not routinely available today. Following traditional rules-of-thumb for selecting casing clearances will likely severely limit the number of casing strings that can be set while drilling the well. Many operators are now challenging the traditional rules-of-thumb for the needed clearance between a casing string OD and the drilled hole during running and cementing operations. Synthetic muds, inhibited muds, and improved cements available today will likely make this rule-of-thumb obsolete very soon. In the past, drilling a hole larger than the last casing string ID was often difficult and costly. Recent advances in concurrent drilling and hole opening technology have made drilling larger than casing ID holes economical and almost trouble free even in larger hole sizes. P. 341^