Proposal This paper discusses the integration of microseismic fracture mapping with fracture engineering, well production results and offset well interference data in the Overton Field, East Texas. Target formation is the Taylor Cotton Valley at depths of about 11,500 ft. The fracturing program in this field included different types of waterfrac and linear gel hybrid frac treatments, which were compared to evaluate the optimal type of fracture design in this area. Detailed production analyses were performed to evaluate well performance in conjunction with fracture geometry measurements provided by microseismic fracture mapping results, calibrated fracture modeling and direct production interference data, which provided interesting insights into effective fracture lengths, reservoir quality, and drainage areas. Microseismic fracture mapping1,2,4,6,7,14–17 indicated that created fractures are very long. There is compelling evidence that effective hydraulic fracture lengths are also very long, as immediate well interference can be detected in wells that are located along the fracture orientation with very large inter-well distances. This means that there is a conductive hydraulic fracture path in place over large distances, with fractures overlapping and linking up wells. One well in this study area was temporarily killed by a fracture treatment in an offset well but production was restored within one day. There was no evidence for a wide fracture network (as has been reported in the Barnett shale), but there may be a small-scale fracture network within a narrow area around the hydraulic fracture. Production modeling indicates that the permeability feeding the long hydraulic fractures (perpendicular to frac) is on average very low as indicated by production modeling. The low permeability and long fractures will create slim "cigar-like" drainage areas that should be taken into consideration for well placement and spacing strategies. The results of this work illustrate the application of microseismic mapping to calibrate fracture models3,8,9,10,13and, with the subsequent integration of production and interference data, to improve well placement and field development strategies. The paper also provides recommendations for optimizing future fracture treatment designs and explores different treament types (waterfracs, and linear gel hybrid fracs) and the effect of increasing job sizes. Introduction The target zones are three to four low permeability gas sands in the Taylor section of the Cotton Valley at depths of about 11,200 to 11,500 ft (Figure 1). Porosities are in the range of 9% to 11% with water saturations of 17% to 30%. Pore pressures are slightly over-pressured at about 0.60 psi/ft. Wells are generally perforated in three to four clusters (one cluster in each sand layer) with 1 shot per foot perforation density. Fracture completions are generally performed in one stage. The type of fracture treatment has evolved over time in several phases, including conventional gel fracs, waterfracs and hybrid fracs. The original crosslinked gel treatments were performed in the 1980's. Waterfrac treatments were implemented in 2001 after the current operator purchased the field. Microseismic fracture mapping was performed on one well and provided measurements of fracture geometry and azimuth. The combination of fracture geometry measurements, fracture modeling, production modeling, and production interference data provided the framework for this study.
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