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Leonard, R. S. (ProTechnics Division of Core Laboratories LP) | Woodroof, R. A. (ProTechnics Division of Core Laboratories LP) | Senters, C. W. (ProTechnics Division of Core Laboratories LP) | Wood, T. M. (ProTechnics Division of Core Laboratories LP) | Drylie, S. W. (StimLab, Inc. Division of Core Laboratories)
Abstract Refracturing continues to provide operators with the opportunity to add production at a fraction of the cost to drill and complete a new well. Various re-stimulation designs and diversion techniques are currently being utilized to maximize contact with previously un-stimulated rock. Optimizing this process involves evaluating all available diagnostic, pressure and production data and determining the optimum design that maximizes recovery. This paper describes how these diagnostic technologies have been employed to evaluate and optimize refracs in four major North American basins. The process of refracturing and recompleting wells continues to improve. Much of this improvement comes from the optimization of techniques through completion diagnostics. Diagnostics provide data that can quantify the amount of the lateral treated and the effectiveness of diversion. Operators are focused on bridging the gap between the completion methods commonly used at the time the well was originally completed and the methods of today. Application of completion diagnostics also assists in identifying opportunities to further reduce the cost of the project while achieving similar results. In this study, proppant tracing followed by spectral gamma ray logging was employed to evaluate the effectiveness of the refracs, the extent of new rock contacted, the benefits of reperforating, and various diversion methodologies. Diagnostic results from 121 vertical (34) and horizontal (87) refracs covering 16 different formations and 26 different operators were analyzed and compared based on stimulation effectiveness and performance. The wells were then grouped by well type, formation and the basic refracturing technique that was utilized. In addition to the macroscopic data interpretation; four case histories are presented from the Barnett Shale, Permian Basin, Eagle Ford, and Haynesville. These case histories include before and after reservoir production matching with fracture half-length and effective conductivity calculations along with the diagnostic analysis of new and existing perforation coverage, diversion effectiveness, and ultimately the % incremental estimated ultimate recovery (EUR).
Abstract This case study helped an operator in the Powder River Basin approach an optimized completion design. The operator used geomechanical measurements, hydraulic fracture modeling, and fracture diagnostics on two horizontal wells. The two wells are near a previously-completed, producing well (i.e., “parent” well). While drilling the two horizontal wells, the operator acquired geomechanics data. This method, called drill bit geomechanics, measured the variability along the laterals. These data produced geomechanically-informed perforation and stage placements to minimize the differences in minimum horizontal stress across each stage. Additionally, the operator engineered the perforation sizes, which increased perforation friction to overcome the measured variability. The authors used the near-wellbore geomechanics data, along with other data, in a hydraulic fracture simulator. In general, standard hydraulic fracture simulators assume constant mechanical properties in each geologic layer. Compared to this standard practice, adding measured geomechanics data can more accurately predict which perforation clusters may be stimulated. To test two different fluid systems, the operator designed a “hybrid” (i.e., combination of slickwater and crosslinked gel) treatment for Well 1 and a slickwater treatment for Well 2. Fracture diagnostics reported their effectiveness. Diagnostics included: 1) proppant tracers to evaluate the perforation efficiency, 2) oil-soluble fluid tracers to quantify by-stage production contribution, and 3) water-soluble fluid tracers to assess inter-well communication. Also, the operator had used proppant tracers on the parent well, providing a baseline for results comparison. Compared to the parent well, the two study wells showed 15-22% higher perforation efficiency. This suggests the engineered design changes created more even proppant distributions. Understanding the geomechanical variability, the operator recognized the engineering required to overcome it. The oil-soluble tracer, although affected by the parent well's depletion profile, showed higher perforation efficiency can increase oil production. Between the two study wells, Well 1 had higher perforation efficiency than Well 2 and it slightly out-produced Well 2. This suggested the hybrid design was likely the more effective design. The hydraulic fracture simulator with near-wellbore geomechanics data predicted perforation efficiency similar to that measured by the proppant tracer. Across both wells’ traced stages, the predicted efficiency and measured efficiency were within 3%. The measurements validated the modeling method. This paper describes a method of improving completion designs through 1) geomechanics data measured while drilling, 2) modeled perforation cluster efficiency, 3) a measurement of proppant placement effectiveness, and 4) an estimate of stage-by-stage production. For the Powder River Basin operator, this method informed decisions about the next completion design iterations. Operators in any unconventional basin could apply this workflow to approach an optimized completion.
The modern hydraulic fracturing process in unconventional shales has relied mainly on the use of mechanical isolation techniques (frac plugs) for internal isolation in between multi-cluster perforated frac stages. Significant benefits exist if mechanical frac plugs can be successfully eliminated from well completions. Recent trends of increased lateral lengths and decreased stage spacing are driving up the number of stages per well and the desire to decrease cycle time between completion and production operations, drive the effort for finding an alternative to mechanical plugs.
This paper presents two case histories of CNX Resources’ wells that utilized various completion techniques to effectively stimulate the laterals without the use of mechanical frac plugs. These ‘plugless’ completions techniques were originally necessitated due to a problem well with a casing patch where standard plug-and-perf completions methods would have required the use of Mechanical Slim Frac Plugs (MSFP) and an undergauge bit for the drillout operation. These MSFPs are designed to pass through internal diameter restrictions and then set and seal properly inside larger diameters. However, after design evaluation, the use of MSFP for internal isolation was found to have some increased challenges associated with the removal of the plug and increased time spent during drillout operations due to the undergauge bit requirement.
Three different plugless completions techniques were selected and then evaluated as a replacement for mechanical frac plugs. Two plugless techniques included the use of a particulate diversion material known as polylactic acid (PLA). The other plugless technique required no particulate diversion material. Proppant tracers and gas tracers were used to evaluate the proppant distribution, cluster efficiency, fracture behavior, and gas returns from each of these techniques. Well productivity was compared to offset wells to quantify the overall success of the plugless completions versus standard plug-and-perf completions. Potential for numerous benefits including reductions in completions costs, operational risks, and cycle times exist with the implementation of plugless completions methods. This case study will lay a framework for operators and service companies to practice and/or evaluate different techniques in completing wells without the use of mechanical frac plugs for internal isolation.
Johnson, M. D. (ProTechnics Division of Core Laboratories) | Pechiney, J. J. (ProTechnics Division of Core Laboratories) | Warren, M. N. (ProTechnics Division of Core Laboratories) | Woodroof, R. A. (ProTechnics Division of Core Laboratories) | Leonard, R. S. (ProTechnics Division of Core Laboratories) | Moore, C. P. (ProTechnics Division of Core Laboratories)
Abstract Horizontal shale gas and oil completion designs have evolved over the last several years. Effective completion design has become extremely important in developing these shale plays. In general, the industry has moved towards longer laterals, more stages, closer spacing between entry points, and increased proppant and fluid volumes. The use of completion diagnostics can be applied to supplement production data and stimulation modeling in optimizing the completion designs and reducing the slope of the learning curve in these emerging shale plays. Fluid and proppant tracer technologies and production profiling have been successfully employed in this optimization process. This paper will present several case histories demonstrating how these completion diagnostic tools have been successfully deployed to assess stimulation effectiveness. Case histories will be presented from the Marcellus, Eagle Ford, Haynesville, and Woodford shales in which these technologies have been employed to characterize proppant placement and load fluid clean-up and to quantify fluid and proppant communication between wells. In these case histories, the diagnostic results were used to evaluate perforation design, fluid and proppant placement as a function of the perforating scheme, lateral coverage, and fluid clean-up as it relates to lateral length, wellbore trajectory, changes in lithology, and frac fluid design. This paper will characterize and validate the role of completion diagnostics in the completion optimization process.
The surge in unconventional completions has created a substantial accumulation of previously hydraulically fractured wells that are candidates for hydraulic refracturing. Completion diagnostics are a valuable tool in determining the most cost-effective stimulation and completion parameters, part of the refracturing optimization process. Refracturing allows the operator to capitalize on this continuous improvement in stimulation design. It also provides an excellent opportunity to add incremental production. The primary purpose of refracturing is to increase production from an existing wellbore through stimulation of new rock and the re-establishing of conductive pathways between the reservoir and wellbore.