Eagle Ford Shale Well Control: Drilling and Tripping in Unconventional Oil and Gas Plays

Abstract

Abstract In late 2010, Shell began an Eagle Ford appraisal program at Piloncillo Ranch in South Texas. These wells are 8,500’ – 9,500’ TVD horizontals, with an average total depth of 14,500’ MD. Their primary target is the Cretaceous Eagle Ford shale. The Shell leases are located in the gas-condensate window. Shell is currently running a five rig development program. Initially, reservoir pressures were thought to be in the 12.5 ppg range, but Diagnostic Fracture Injection Tests (DFITs) showed the actual pore pressure to be greater than or equal to 14 ppg. Initially, underbalanced drilling techniques were used to drill the 14-14.5 ppg formation with 11 ppg oil based mud. The Eagle Ford has no natural fractures in this area. As more wells were drilled, however, completion fracturing of offset wells began to cause well control problems, as induced fractures were encountered in horizontal sections during drilling. Initially, it was thought that additional casing strings would be required to deal with the higher pressures and flow capability of the 14-14.5 ppg fracture; however, through well control modeling and experience with underbalanced drilling in other tight gas environments, tripping and heavy pill spotting procedures were developed that allowed the wells to be drilled with the initial casing program. This paper will describe the development of fit for purpose well control techniques used to drill underbalanced horizontal wells in the Eagle Ford shale gas play. It will discuss how the characteristics of tight shale formations in horizontal wells resulted in a different approach to well control and tripping procedures. Several simple techniques for establishing an understanding of real time data have helped to make decisions in the field with current information: Institute a dual density system to stop reservoir flow and prevent up-hole lossesCreate a Horner Plot for distinguishing ballooning from reservoir flow if losses are experiencedCreate a mud weight vs. influx flow plot for predicting flow changes with mud weightAscertain how the influx rate and location affect the time at which it would a take a well to unload to dry gas The paper will also describe the software modeling used to determine influx responses and the methodology developed around it. This methodology is applicable to other tight shale formations drilled horizontally and developed around the globe. These procedures can significantly reduce non-productive time and minimize serious well control events on horizontal shale wells when properly followed.