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.
The deep Anadarko Basin of Western Oklahoma and part of the Texas Panhandle is an area known for deep, tight, gas wells. These wells can reach average depths of 12,000 ft to 18,000 ft and some may be drilled as deep as 20,000 ft. To say the area produces some very prolific wells would be a gross understatement, given post completion production rates of 13 million cubic feet of gas/day, or more for many wells. Some of the deepest, and most challenging wells drilled are in Roger Mills, Custer, Beckham, Washita, and Caddo counties of Oklahoma, and Hemphill and Wheeler counties of Texas. The most common target formations are Pennsylvanian Sands, most notably the Granite Wash, Red Fork, Morrow, and Springer.
Although the characteristics vary from well to well and field to field, most of these sands can be described as having low permeability, with 0.1 md or less being common. The pore pressure gradients generally average less than 0.8 pounds per square inch, per foot of depth (psi/ft). Many Springer or Morrow wells may have slightly higher pore pressures. Although mud densities greater than 18.0 pounds per gallon at total depth on a Springer well are not unheard of; they are uncommon. The drilling mud used to drill the productive intervals can be either a low solids, water based system with densities in the 10.3 to 13.0 pound per gallon (lb/gal), or invert oil based at 14.5 to 18.0 lb/gal. The use of the invert oil based mud is due to the need for hole stability while drilling through the water sensitive Atoka Shales on some of the deeper Morrow and Springer wells. Temperature gradients in this part of the basin are low, averaging from 0.9 to 1.2 degrees Fahrenheit per 100 feet of depth. These temperature gradients will generally yield bottom hole static temperatures in the range of 190 to 270 degrees Fahrenheit. Fracture gradients generally run from a low of about 0.75 psi/ft for the Granite Wash wells to 0.95 psi/ft or more for some Springer wells. P. 349