Research sponsored by the Gas Research Inst. (GRI) indicates unbroken fracture fluids can lower gas reserves by 30%, reduce initial gas rates by 80%, and delay fracture-fluid cleanup by weeks or months. The unbroken fracture fluids flatten the production profile. In extreme cases, gas production slowly increases for weeks or months despite constant flowing pressures. The fracture fluids must break to a viscosity of 50 cp or less to ensure that gas reserves are maximized.

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Historic "sweet spots", areas of well-to-well interference, and infill potential were determined for an 1800 well area of the OZONA (Canyon) field using a new approach that focuses on the age of the wells, their location, and production profiles. At the core of this new approach, termed "moving domain", is a mosaic of automated studies that draw statistical conclusions about well performance, depletion, and undrained acreage. Preliminary infill estimates in one to two weeks are possible and the technique is typically linked to conventional reservoir engineering to improve estimates. When applied to OZONA (Canyon), 1246 infill locations were identified with 636 Bcf of gas reserves. Introduction History - The OZONA field, located in Crockett County in Southwest Texas (Figure 1) contains two major producing sands, the Canyon and the Penn. These sands are complex turbidite deposits that are characterized by numerous gas productive members with permeabilities from less than 0.001 mD to over 0.10 mD and are found at depths of 6,000 to 8,000 ft.1 A recent change in field rules will allow drilling to 40 acres spacing in most parts of the field. Initial development began in the early 1960s on 320 acre spacing, with subsequent infill drilling on 160- and 80 acre spacing. Typical completions require fracture treatments using water based fluids containing 50 to 250 klbs of 20/40 sand to achieve economic production rates. Ultimate gas recoveries range from 200 MMCF to over 2000 MMCF and can vary significantly from well to well. Historically, many wells with multiple pay zones were fracture treated simultaneously, while other wells were fracture treated in isolated stages. Problem - Quantifying the infill potential in the OZONA (Canyon) field is difficult for several reasons: the layered and low permeability nature of the reservoir, the hydraulic fracturing of wells, the variation in well spacing, and the local and regional variations in rock quality. These complicating factors often cloud the extent of depletion, benefits of improved completion and operation techniques, and make the quantification of infill potential rather difficult. Because of these complexities and the fact that our study area contained over 1000 wells, the time and cost requirements of a conventional reservoir engineering study were unacceptable. Instead we applied a new technique that was found to be useful in a large tight gas field in East Texas.2

Research sponsored by the Gas Research Institute indicates unbroken fracture· fluids can lower gas reserves by 30%, reduce initial gas rates by 80%, and delay fracture fluid clean-up by weeks or months. The unbroken fracture fluids slow fracture fluid cleanup and flatten the production profile. In extreme cases, gas production slowly increases for weeks or months despite constant flowing pressures. The fracture fluids must break to a viscosity of 50 cp or less to ensure that gas reserves are maximized. INTRODUCTION Many tight gas wells do not respond to hydraulic fracturing as expected. Following stimulation, a typical tight gas well achieves a high initial gas rate within a few days after stimulation and then experiences a steep hyperbolic production decline. Some tight gas wells, however, do not achieve an obvious production peak but instead sustain a flat production profile or exhibit a slowly increasing production rate for several weeks or months. Fig. 1 illustrates this type of performance for several wells completed in the Frontier formation.1 As shown by Fig. 1, the production can increase for up to three months before reaching a peak rate and then decline slowly. The peak rates shown in Fig. 1 are less than the peak rates expected from these wells. The production behavior shown in Fig. 1 is attributed to slow fracture fluid cleanup.1 Multiphase flow and fracture face damage contribute to this type of productive behavior,2 however, one mechanism that has not been directly evaluated in the past is the effect of the viscous gel in the proppant pack. A viscous, unbroken fracture fluid inhibits the flow of gas, water, and broken fracture fluid through the fracture, compounding the effects of fracture face damage and proppant pack conductivity reduction due to gel residue.

Background. Identifying the locations and amounts of unproduced gas in mature reservoirs is often a challenging problem, due to several factors. Complete integrated reservoir studies to determine drilling locations and potential of new wells are often too time-consuming and costly for many fields. In this work, we evaluate the accuracy of a statistical moving-window method (MWM) that has been used in low-permeability (“tight”) gas formations to assess infill and recompletion potential. The primary advantages of the technique are its speed and its limited need for data, using only well location and production data. Method of Approach. To test the method, we created a number of hypothetical reservoirs and calculated infill well potential using a reservoir simulator. We used the MWM to analyze these data sets, then compared results to those from the reservoir simulations. Results. The results validate empirical observations made using MWM during field evaluations. Depending on the level of reservoir heterogeneity, the MWM infill predictions for individual wells can be off by more than ±50%. The MWM more accurately predicts the production potential from a group of infill candidates, the MWM, however, more often to within 10%. We describe a procedure to estimate the number of wells needed to predict production potential to within a stipulated accuracy. The ability of MWM to accurately predict production performance for groups of wells shows that it can be a useful tool for scoping studies or identifying areas for more detailed evaluation.