A Study of Stimulation Results of Ellenburger Gas Wells in the Delaware-Val Verde Basins

Abstract

Abstract A statistical study of deep Ellenburger gas wells in the Delaware-Val Verde basins of West Texas has indicated a new evaluation method for use in analyzing these gas well completions. Summation of calculated open-flow potential tests on drillstem tests can be used to estimate the ultimate calculated absolute open-flow potential (CAOFP) of a well. Statistical data indicate the most favorable results are obtained with relatively small volume acid treatments (25,000 gal or less). Introduction Recent acceleration of deep Ellenburger gas well activity in the Delaware-Val Verde basins has evoked many questions as to the best methods of stimulation and the evaluation techniques available to the industry for this type of well. Because of the deep, expensive drilling and the associated high completion costs, a method of comparing stimulation results was needed. A technique is proposed that makes use of limited data such as one flow rate on a drillstem test or one flow rate prior to stimulation. By estimating a calculated open-flow potential from this one point, it is possible to estimate results from completion and stimulation. The technique of estimating the CAOFP from the one flow rate offers a tool of comparison to the geologist as well as the engineer. From scout data, the estimated CAOFP on various gas wells in isolated areas may be evaluated where it is difficult to obtain a comparison using flow rates through different choke sizes and with different flowing pressures. Data for this study were obtained from CAOFP tests from the Railroad Commission of Texas and from scout reports. In all, 45 wells in eight Ellenburger fields, ranging in depth from 13,000 to 22,000 ft, provided sufficient information for this study. Procedures for Data Analysis Previous evaluations of results in treating gas wells were based on a comparison of deliverability tests where these data were available. To make this type of comparison, all wells evaluated would have to be tested at one common backpressure, i.e., 1,000 psi surface pressure. These types of data are not available on enough wells to permit any type of statistical analysis using a large number of randomly selected wells. Since, in gas wells, the accepted measure of a well to produce is the CAOFP, which is the flow calculated with 0 psi backpressure at the formation face, the CAOFP then is the basis of comparison used in this study. Upon establishing a basis of comparison, well data were examined in the Brown-Bassett, Coyanosa, Gomez, Hamon, JM, Puckett, West Waha and Worsham-Bayer fields. Because few companies obtained tests under natural conditions prior to stimulation, it was necessary to examine drillstem tests as an indication of the capacity of a Well to produce. Therefore, the assumption is made for this study that the CAOFP of each zone drillstem tested within the Ellenburger is additive with other sections tested in the well. The sum of all the flowing DST's indicates the natural flow capacity of the well. This addition assumes no over-lapping of productive intervals or interflow between productive intervals. Another premise is that untested sections were indicated to be nonproductive when penetrated. Since in most cases where data were available only one flow rate was obtained on the DST, a slope parallel to the final slope obtained on the four-point test was used to determine the CAOFP of any given DST or flow rate with one point. Several methods can be used to determine the flowing bottom-hole pressure required to give the one point for constructing the line for the CAOFP. Flowing bottom-hole pressure can be calculated from flowing surface pressures with the method used by the Railroad Commission of Texas or one published by Guerrero. These and other methods take into consideration producing rate, gas gravity, average producing depth, tubing size and flowing temperature and pressure. These methods of calculating flowing bottom-hole pressures or bottom-hole pressures obtained from flowing drillstem tests can be utilized to determine the CAOFP of a well or zone. Previously it has been necessary to try to account mentally for differences in choke size, flowing surface pressure and rates. JPT P. 1017ˆ