Oil and gas wells with compromised integrity are a concern because they can potentially leak hydrocarbons or other fluids into groundwater and/or the atmosphere. Most states in the United States require some form of integrity testing, but few jurisdictions mandate widespread testing and open reporting on a scale informative for leakage risk assessment. In this study, we searched 33 US state oil and gas regulatory agency databases and identified records useful for evaluating well integrity in Colorado, New Mexico, and Pennsylvania. In total, we compiled 474,621 testing records from 105,031 wells across these states into a uniform dataset. We found that 14.1% of wells tested prior to 2018 in Pennsylvania exhibited sustained casing pressure (SCP) or casing vent flow (CVF)—two indicators of compromised well integrity. Data from different hydrocarbon-producing regions within Colorado and New Mexico revealed a wider range (0.3 to 26.5%) of SCP and/or CVF occurrence than previously reported, highlighting the need to better understand regional trends in well integrity. Directional wells were more likely to exhibit SCP and/or CVF than vertical wells in Colorado and Pennsylvania, and their installation corresponded with statewide increases in SCP and/or CVF occurrence in Colorado (2005 to 2009) and Pennsylvania (2007 to 2011). Testing the ground around wells for indicators of gas leakage is not a widespread practice in the states considered. However, 3.0% of Colorado wells tested and 0.1% of New Mexico wells tested exhibited a degree of SCP sufficient to potentially induce leakage outside the well.

TX 75083-3836, U.S.A., fax 01-972-952-9435. ProposalThis 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 mapping 1,2,4,6,7,14-17 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 interwell 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 "cigarlike" 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 models 3,8,9,10,13 and, 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.