Recommendations for stimulation optimization in mature fields often meet with opposition from operators who are wary of changes in the design of well completions. Often, inertia exists among personnel because they are comfortable doing things the way they have been doing them and because they want to avoid the potential risk of a new idea. A common set of concerns regarding low-permeability gas reservoirs is how much the changes will cost and whether or not they will result in adding new reserves. To answer these questions, the reservoir must first be studied and analyzed so that a reasonable prediction can be made regarding the maximum potential of the well. An effective approach is to form an integrated team made up of specialists from both the operating and service companies to gather and process comprehensive information. This information should include data from reservoir engineering, drilling, petrophysics, geology, stimulation design, and production and completion operations. This team approach was applied to the low-permeability Lewis and Almond sands in the Wamsutter field in southwest Wyoming. A team began studying the reservoir in 1998 to better understand the problems that prevented the wells from producing at their maximum potential. The team was challenged with the following tasks:Determine whether or not the wells were already performing as well as they could.Establish a benchmark by which to measure the success of any changes.Identify the major causes of underperformance.Apply new technologies and techniques to overcome the causes of underperformance.High-grade pay based on log evaluation, individual zone testing, and production logging.Design stimulation treatments that maximize the net present value from the well.Document the effect of specific changes in completion practices. At the outset, a benchmark of the 90-day average production rate was established based on existing results. As a result of this ongoing effort, the original benchmark has been exceeded by over 100% over the past five years. The average production for these wells has also increased more than 50%. Introduction The Wamsutter field is located in the eastern part of the Green River Basin of southwest Wyoming (Fig. 1). Since its discovery in 1958, there have been over 2,300 wells drilled in the area. The reservoir consists of stacked marine and fluvial sands of the Mesaverde Almond formation and the numerous turbidite flows within the Lewis Shale (Fig. 2). These sands typically have 8–12% porosity and 0.002–0.030 mD permeability with initial reservoir pressure ranging from 0.43–0.58 psi/ft. In some cases, the Almond Bar could show some pressure depletion from parent well production. Since the drainage area of these sands is typically 80 acres or smaller, not all sands will be penetrated in each well. However, the average net pay footage ranges between 50 and 80 ft per well.

In June 1996, a two-phase project was initiated to determine how multiplezones react to fracture-stimulation treatments in the Mesa Verde formation, which is located in the Piceance Basin of the western Rocky Mountain Region in the U.S. On the basis of the collected information, study participants evaluated and redesigned procedures to increase the operator's profitability. Limited-entry fracturing was used as the primary fracturing technique, and a multiple-isotope, spectral gamma ray imaging tool was used for evaluating early, middle, and late proppant distribution with three isotopes. During the two-phase project, 20 wells and 218 sands were perforated and targeted for stimulation. Phase 1 Study Treatment Description. Between June and December 1995, 13 hydraulic fracture-stimulations were performed on 10 wells in the Piceance Basin. All treatments consisted of a 35-lb borate system and 20/40sand. Treatments were pumped at a rate that allowed 1,000-psi differential pressure across the perforations. Each stimulation was pumped with three radioactive tracers: the first isotope was used with the first 10,000 to 30,000 lb of sand, the lastisotope was used in the last 40,000 to 50,000 lb of sand, and the second isotope was used with the sand volume between these two ranges. Because perforation erosion occurred almost immediately after sand entry, operators were able to switch quickly from the first to the second isotope; the difference in distribution before and after this erosion was then illustrated. The final isotope would indicate any changes in distribution between sands occurring during the job that were caused by net pressure and geometry changes. A limited-entry pumping procedure was used for all treatments, with 5 to 10sands per treatment. A total of 17 to 22 holes were used for each stimulation(two to five holes per sand).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractRecommendations for stimulation optimization in mature fields often meet with opposition from operators who are wary of changes in the design of well completions. Often, inertia exists among personnel because they are comfortable doing things the way they have been doing them and because they want to avoid the potential risk of a new idea. A common set of concerns regarding low-permeability gas reservoirs is how much the changes will cost and whether or not they will result in adding new reserves. To answer these questions, the reservoir must first be studied and analyzed so that a reasonable prediction can be made regarding the maximum potential of the well. An effective approach is to form an integrated team made up of specialists from both the operating and service companies to gather and process comprehensive information. This information should include data from reservoir engineering, drilling, petrophysics, geology, stimulation design, and production and completion operations.This team approach was applied to the low-permeability Lewis and Almond sands in the Wamsutter field in southwest Wyoming. A team began studying the reservoir in 1998 to better understand the problems that prevented the wells from producing at their maximum potential. The team was challenged with the following tasks:• Determine whether or not the wells were already performing as well as they could. • Establish a benchmark by which to measure the success of any changes. • Identify the major causes of underperformance.• Apply new technologies and techniques to overcome the causes of underperformance. • High-grade pay based on log evaluation, individual zone testing, and production logging.• Design stimulation treatments that maximize the net present value from the well. • Document the effect of specific changes in completion practices.At the outset, a benchmark of the 90-day average production rate was established based on existing results. As a result of this ongoing effort, the original benchmark has been exceeded by over 100% over the past five years. The average production for these wells has also increased more than 50%.