This paper presents a case history of hydraulic fracture stimulation treatments performed on a vertical well completion in the Spraberry-Wolfcamp formations located in Midland County, Texas, in which real-time microseismic Hydraulic Fracture Monitoring (HFM) was utilized to "track" the development of the hydraulic fracture as it propagates through the formation thereby allowing for the implementation of corrective actions to improve the completion efficiency of the well.The case history is presented in three main themes or sections: background, job execution, and post-job evaluation. The background section will provide an overview of the completion design as well as the HFM setup. The job execution section will then address how the real-time HFM observations and interpretations made during the treatment executions were used to identify undesired height growth, which prompted swift and concise actions to optimize the well completion by modifying the perforation scheme and treatment design. Finally the paper will present the results of the integrated HFM post-treatment evaluation and will discuss the observed differences between the planned and actual fracture geometries as observed from the microseismic monitoring results. Comparison of the microseismic fracture geometry to the anticipated fracture geometry showed that even in areas where we think that there might not be anything new to be learned, opportunities exist to apply new technology that can identify some of the complications and challenges involved, improve the success of stimulation treatments, and identify opportunities to improve operational efficiency.Overall, this example clearly shows how real-time microseismic monitoring provides the data required to improve fracture modeling, identify fracture behavior that is not predictable by conventional means alone, and reveals several opportunities to improve completion efficiency.

The process of abrasive jet perforating deployed on coiled tubing (CT), fracturing down the CT and casing annulus, and isolation with proppant plugs has proven beneficial in reducing completion costs and improving operational efficiencies in multistage stimulation applications. Unlike conventional plug and perforation techniques, this process can be done in a single trip, allowing the well to be put on production immediately after the treatment because no bridge plugs have to be drilled. However in horizontal well applications, achieving isolation with proppant plugs can be very challenging due to gravity effects, proppant plug integrity concerns, and ease of fracturing the formation. Adding degradable fibers to proppant plugs has proven successful in achieving good isolation between stages in horizontal wellbores. The fibers not only help create bridging at the perforations, but they also keep the proppant from settling to the bottom of the pipe thereby maintaining the integrity of the proppant plug. This approach has been used successfully in several abrasive jetting fracturing treatments in horizontal wells in West Texas and Southeast New Mexico. Well completion times have been reduced from over a week to only two to three days while allowing for more intervals to be selectively stimulated. Initial production results from the wells completed with the new technique have considerable improvement compared to previous stimulation methods.

fax 01-972-952-9435. AbstractThis paper discusses the selection criteria, design methodology, and analysis of hydraulic fracturing treatments pumped using a solids-free, liquid CO 2 foam-based viscoelastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast New Mexico (SENM).The wells discussed in the paper were completed in various Morrow Sand intervals around 10,500 ft with an average Bottom Hole Static Temperature (BHST) of 190 o F. Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive formations, high rock Youngs' Modulus and unpredictable occurrence of water-bearing zones, lead to the selection of foamed VES fluids. This technology was successfully applied in the Morrow Sands in Eddy County of SENM. Fracture geometry analysis using surface treating pressures, radioactive tracers and production data, showed height growth containment and longer effective fracture half-lengths. Results also indicated successful stimulation past the cement squeezed intervals and temporary liner tie-backs run in to overcome lower pressure constraints. Finally, lower friction pressures helped in designing economical fracture stimulations for mature wellbores thereby generating an opportunity to recover otherwise bypassed hydrocarbon reserves.

fax 01-972-952-9435. AbstractThis paper discusses the selection criteria, design methodology, and analysis of hydraulic fracturing treatments pumped using a solids-free, liquid CO 2 foam-based viscoelastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast New Mexico (SENM).The wells discussed in the paper were completed in various Morrow Sand intervals around 10,500 ft with an average Bottom Hole Static Temperature (BHST) of 190 o F. Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive formations, high rock Youngs' Modulus and unpredictable occurrence of water-bearing zones, lead to the selection of foamed VES fluids. This technology was successfully applied in the Morrow Sands in Eddy County of SENM. Fracture geometry analysis using surface treating pressures, radioactive tracers and production data, showed height growth containment and longer effective fracture half-lengths. Results also indicated successful stimulation past the cement squeezed intervals and temporary liner tie-backs run in to overcome lower pressure constraints. Finally, lower friction pressures helped in designing economical fracture stimulations for mature wellbores thereby generating an opportunity to recover otherwise bypassed hydrocarbon reserves.

No abstract