Neil A. Stegent

Optimizing Lateral Lengths in Horizontal Wells for a Heterogeneous Shale Play

A successful evaluation and development program in oil- and gas-bearing shales requires considerable analysis and investment, not to mention optimization to help ensure a profitable outcome. Accelerating optimization, reducing capital expenditures, and improving lifecycle net present value (NPV) for the asset are reasonable goals. Seven shale properties are key drivers to help achieve successful play economics. However, the heterogeneity of shales makes well location selection difficult without appraisal well logs and geostatistical mapping of shale property quality. The analysis method allows operators to quickly high-grade areas within a large, heterogeneous shale play using logging suites from a limited number of wellbores in the play. Further, the methodology has been extended to quantify the play’s potential reward versus risk distribution for in-fill drilling investments. This study extends the method to optimizing lateral lengths of horizontal wells. Geostatistics provides a means to determine correlation lengths of aggregate shale properties known to be critical to successful economics. The correlation length is used to determine the appropriate length of the horizontal well lateral, restricting it within the highest rock quality for stimulation effectiveness and production rates. Because optimal lateral lengths can be predicted using this approach, it is now possible to pinpoint the best wellhead location, the best landing point for the horizontal portion of the well, and set the optimal length of the lateral. This reduces the drilling of unproductive lateral lengths and targets stimulations. By shortening the “trial-and-error” evaluation lifecycle stage using this methodology, an operator can develop an asset more quickly and at less cost than with previous approaches.

Unique Solution to Repair Casing Failure in a HP/HT Wellbore Allows for Successful Multistage Stimulation Treatment in an Unconventional Reservoir

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. Introduction The Eagle Ford shale completions, along with most other unconventional plays, require multi-stage high pressure hydraulic fracturing stimulation treatments to produce at economically viable production rates. Even though treating pressures stay well below the mechanical limits of the tubulars, casing failures can still occur. Many of these failures are attributed to the cycling of high pressures as well as extreme temperature fluctuations that occur in hydraulic stimulation treatments. These pressure and temperature conditions create large forces for the wellbore to endure. Accounting for tension, compression, buckling and ballooning, and thermal effects makes wellbore design critical. In this case study, a coupled connection failed in the vertical section above the crossover between the 5-1/2-in. and 4-1/2-in. production casing. The well was repaired by placing a 4-in. liner, which was anchored in place using swellable packer technology, across the casing failure. A flow-thru frac plug then was developed that would travel through the smaller 4-in. ID liner and could be set in the 4-1/2-in. lateral to isolate each section between frac stages. This repair allowed for the successful stimulation of multiple stages of casing fracture treatments, enabling the well to be produced economically. Challenges Created by Casing Failure Certain failures result when exceeding the physical properties of the casing, though in this particular instance, a metallurgical defect yielded the casing at a coupled connection. This particular wellbore used the most common wellbore configuration in the Eagle Ford at the time; i.e., a 5-1/2 inch 23 lb/ft P-110 casing in the vertical wellbore and 4-1/2 inch 15.1 lb/ft P-110 casing below the kick-off point into the horizontal section. The casing experienced a failure at 9208 psi or 64% of burst pressure (14420 psi) after pumping 1050 bbls total slurry on stage one (

Unique Solution To Repair Casing Failure in an HT/HP Wellbore Allows for Successful Multistage Stimulation Treatment in an Unconventional Reservoir

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.