fax 01-972-952-9435. AbstractShallow gas and water flows are a major concern when cementing deepwater wells in many Gulf of Mexico fields, often requiring expensive remedial work, premature well abandonment and respudding. Entire templates can be compromised if a single cement job on surface pipe fails to provide zonal isolation from the shoe up to the mud line.
Traditionally, service companies have had to place several consecutive cement plugs to successfully kick off wells deeper than 3,500 meters. Within the scope of integrated projects in Southern Mexico where wells are usually deeper than 5,000 meters, the low success rate for traditional balanced plug cementing has jeopardized operational efficiency and financial results. Several plug failures made it clear that the volumetric calculations and other known engineering best practices that were implemented were not sufficient to bring the success rate to an acceptable level. In our field study, we implemented an innovative simulation and design method that allows for engineered optimization of the plug placement design and that shows how a 100% success rate in plug cementing can be achieved in wells as deep as 5,720 meters, with hard formations and an OBM environment. The value of this new method resides in a live analysis and display of the fluid interfaces, mixing both while traveling down the pipe and up the annulus and resulting in the output of an estimated top of uncontaminated cement after pulling the pipe out of the hole. The new workflow reveals the effect of each variable affecting the amount of contamination of the cement slurry downhole and gives the engineer the opportunity to optimize the plug placement design before job execution to reach the highest possible top of uncontaminated cement after execution. The results obtained with the new engineering tool and a precise operational field execution has moved the theory of plug placement from the best practice library to the reality of the plug placement operations.
Plug and Perf (PnP) has been predominant for years as the preferred completion method for unconventional reservoirs. However this technique can be costly and time consuming. The Coiled Tubing Activated Frac Sleeves (CTAFS) technique utilizes fracture sleeves that can be hydraulically opened using coiled tubing and fractured through the annuls, minimizing time between stages and reducing total fluid consumption. This paper evaluates the fracturing and production performance of the Plug and Perf technique compared to Coiled Tubing Activated Fracture Sleeves (CTAFS) in a US shale oil play (Eagle Ford) and in tight sand reservoirs (Cotton Valley, Bone Spring and Granite Wash). It focuses on a strategy of improving ultimate recovery by using fracturing modeling, proper completion selection and field data to determine the optimal stage spacing of the multistage completion systems (PnP and CTAFS). The fracture models were created using existing logs and geomechanical modeling results in the surrounding area to create an optimal geometric spacing for the stages. The basics of the primary multistage completion systems are discussed and briefly compared from an operations point of view. Effective fracture dimensions can be achieved by selecting better locations for the stage clusters in Plug ad Perf and single fracture injection points using Coiled Tubing Activated Frac Sleeves (CTAFS). Fracture treatment schedules for each completion technique are recommended in terms of proppant type, concentration, fracture fluid type and volume. Two different fracture treatments were used to analyze the effect of fracturing fluid and completion type on fracture geometry. Coiled Tubing Activated Frac Sleeves with an optimized fracture treatment schedule outperformed the PnP as it fully controls fracture placement, leading to bigger drainage areas. For PnP, cumulative production decreased with an increasing number of clusters and the less efficiency of the stages on productivity. Adding more sleeves accelerated the EUR because of a larger drainage area. The CTAFS technique allowed tighter spacing of frac stages and ensured that the fracture was created at the sleeve in contrast to PnP technique in which some zones could remain untreated.
La investigación se llevó a cabo en una empresa de producción industrial y exportación de envasados de Concholepas concholepas, situada en la ciudad de Tacna, Perú. Se determinó dos variables de calidad que tienen relevancia en el producto final; el volumen del envase y la proporción porcentual de proteínas en la unidad, seguidamente se terminó el diagrama de medias, para la variable volumen en 452,356 g como promedio del proceso, con límites de control superior, de 454,514 g y límite inferior de 450,198 g, en cuanto a su rango se estableció la línea central o promedio del rango en 3,74167 g con límite de control superior de 7,91171 g y un límite inferior de 0,0 g. Para la proporción de proteínas, se observó una proporción promedio de 15,24 % con límites de control superior e inferior de 16,40 % y 14,08. Respecto a su diagrama de rangos, se encontró un promedio del rango de 2,0 %, con límite de control superior de 4,25 % y límite de control inferior de 0,0 %. En los diagramas de control se observa que el proceso en la producción respecto a volumen y la proporción de proteínas de producto envasado, se encuentra en control estadístico dado que todas las puntuaciones obtenidas se encuentran dentro de los límites de control de calidad.
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