fax 01-972-952-9435. AbstractIn this case study we address the problems associated with fracturing tight gas sands when nearby water sands are present. Often times the problem is that the created fracture might intersect the water sands which can impede the gas production and in extreme cases can kill the well. Production forecasts based on calibrated permeability values can be performed to show the impact of water production to gas production. If the production forecast indicates that there is enough gas to unload and carry the water to surface then an optimized larger fracture treatment based on effective and relative permeabilities can be performed across both gas and water intervals. If there is not enough gas present to unload the water then the fracture treatment must be carefully designed such that the fracture length is still optimized and water penetration does not occur.Around the world, strands of tight natural gas resource lie unproduced next to and within water bearing sands. The production optimization process that is described combines several completion techniques that incorporate currently available technology to give the completion engineer one more tool to gain access to these reserves. This technique is not geographically limited and applies to any tight gas sand resource.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe Oligocene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin, high-quality sands have been overlooked. These sections can now be discerned using microresistivity measurements in oil-based mud systems and new highresolution cutoffs can be employed. A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysically consistent high-resolution permeability estimate, fracture geometry prediction, and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets with the old cutoffs.Over a two-year drilling program, data gathered from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field. This integrated process of measurement, analysis, prediction, evaluation, and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of South Texas.

The Oligocene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin, high-quality sands have been overlooked. These sections can now be discerned using microresistivity measurements in oil-based mud systems and new high-resolution cutoffs can be employed. A production prediction model is critical to enhance the chance of success. The model used here employs a petrophysically consistent high-resolution permeability estimate, fracture geometry prediction, and formation pressure. The methodology identified several sands as commercial that have been bypassed in offsets with the old cutoffs. Over a two-year drilling program, data gathered from several field example wells were analyzed. These are presented here to illustrate how production data was utilized to continuously adjust and calibrate the high-resolution petrophysical model. The incremental revenue from the added pay exceeded the cost of this new methodology and enhanced the economic viability of the field. This integrated process of measurement, analysis, prediction, evaluation, and model adjustment enables the operator in South Texas to make timely completion decisions as well as set-pipe decisions. This process is becoming a useful tool for further exploitation of the mature Oligocene Vicksburg formation of South Texas. Introduction The Vicksburg formation in South Texas has been exploited since the 1920s and is still a prolific producer with over 20 Bcf per year average rate (Fig. 1). The play has seen both productivity increases and declines depending on gas prices and technology drivers. Since the mid-1990s, however, the trend has been ever-decreasing productivity and faster rate declines. At the same time, only 12% of the estimated 3,860 Bcf ultimate recoverable designated tight gas in Vicksburg has been produced,[1] leaving much to be recovered. Some of this recovery can be enhanced with recently developed high-resolution technology. The decision on whether to set pipe or complete a particular zone usually is made once the logging run is complete. During the standard logging run, the analyst will view the density porosity output and question the economics. "What is the porosity cutoff to make a well here"? The answer is found over years of experience and the school of hard knocks. Typically a "Rule of Thumb" is used and a line is drawn (Fig. 2). Many South Texas partners make their decisions based on these cutoffs and individual experience. Worthington gives a comprehensive perspective on the use of these cutoffs.[2] The cutoff number most often used in the Oligocene Vicksburg trend of South Texas is 15–16% porosity (Fig. 2). More recently there has been success at much lower porosity in the range of 8–10%.[3] Obviously, if a 16% porosity cutoff was applied routinely, then somewhere in the thousands of wells drilled, some pay has been bypassed. One solution that has been used primarily in water-based systems has been laminated sand analysis. This type of analysis has been applied since the early 1990s primarily in turbidite plays[4] and not verified with production. The analysis used here verified with production data, provides a better answer for the less obvious and often bypassed pay sands.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe advent of a viable formation resistivity measurement through-casing has allowed for an order of magnitude increase in the confidence of through-casing formation evaluation.