Unique Solution to Repair Casing Failure in a HTHP Wellbore Allows for Successful Multi-Stage Stimulation Treatment in an Unconventional Reservoir

Abstract

Horizontal shale completions require multi-stage high-pressure hydraulic fracturing stimulation treatments in order to deliver commercially viable production in low permeability reservoirs. Unconventional shale plays, such as the Eagle Ford and Haynesville Shale, often can require stimulation treatments that must be implemented in high pressure and high temperature (HPHT) conditions. Typically, these wells are completed with long casing strings, and it is critical that these monobore casing strings withstand high injection pressures as well as maintain mechanical integrity during thermal contraction/expansion. So what happens when the pre-frac casing pressure integrity pressure test fails? What is the "fix" that will allow treatments to be pumped at high pressure and rate? How will frac stages be isolated during the completion? Typically, remediation techniques have included everything from casing patches and expandable casing to coiled tubing completions. Unfortunately, these solutions can have pressure limitations, and in addition, can be cost prohibitive. The authors of this paper will discuss how design of a 4-in. tie-back string with flush joint connections equal to the properties of the casing was capable of repairing a 5-1/2-in. monobore production casing that experienced extensive casing failure. The extremely small annular tolerance did not allow a conventional packer assembly or cementing for pressure isolation; thus, swellable packer technology was used to anchor the casing in place. A special flow-thru frac plug was designed so that it could be pumped through the 4-in. tie-back casing and set in the 4-1/2-in. lateral, allowing a plug-and-perf fracture completion to be performed. The stimulation treatments were pumped to completion and demonstrated 1), that the pressure isolation integrity of the casing system was satisfactory; and 2), that the flow-thru frac plugs could maintain isolation between stimulation treatments. This wellbore was in the Eagle Ford Shale. True vertical depth (TVD) was ~ 13,000 ft, bottomhole temperature (BHT) was ~325°F with a 0.95 psi/ft frac gradient, and surface pressures exceeded 10,000 psi during the stimulation treatments.

Modeling, Testing, and Case Histories of Swellable Packer Casing Anchoring Performance Enable Wells Destined for Plug and Abandon to Become Producers

“…Nine total stages were successfully stimulated, allowing the well to become productive. (Wellhoefer, B., et al, 2012) In a collection of eight wells in East Texas, an operator wanted to run swellable packers to perform a short-term temporary application for chemical injection. The operator planned to run swellable packers to perform a chemical injection in the annulus, and then, to pull the tubing and unseat the packers in six months to pull the tubing out of the hole.…”