Abstract This paper presents a unique process for deriving reservoir properties (i.e., minimum horizontal stress, kh/u and reservoir pressure) in isolated reservoir layers intersected by the same wellbore. It is based on simultaneously performing multiple diagnostic fracture-injection tests (DFIT) with extended multi-day shut-in periods using downhole shut-in tools and bottomhole memory gauges. A case study of 58 wells completed in the Mesaverde and Dakota sandstones of the San Juan Basin is used to describe and assess the above application. These intervals are gas productive, slightly to significantly sub-pressured, and possess a very low permeability pore network enhanced by natural fracture networks. As many as seven individual intervals per well were tested using the simultaneous process in an area spanning the entire San Juan Basin. Large scale, multi-stage hydraulic fracturing is necessary to establish commercial production from these intervals. The diagnostic tests were done prior to the large-scale fracture treatments, yet did not impede the subsequent implementation of the treatments. In the Dakota interval, the diagnostic testing results agreed well with the kh derived from post-frac production analysis and led to a process of treatment design optimization. In the Mesaverde interval, less agreement was found between diagnostic test and production analysis results. Despite the lack of validation, fluid leak-off rates measured during the diagnostic testing provided insight into fracture half-length differences documented in a previous study of microseismic mapping. As part of the case study, procedural guidelines and best practices developed in the process of doing over 200 tests will be discussed. Multiple Diagnostic Fracture Injection Tests Done Simultaneously in a Single Wellbore The method to perform multiple diagnostic fracture injection tests (DFIT) simultaneously in a single wellbore came from the need to characterize mature formations which were differentially pressure depleted. The majority of oil and gas reservoirs the San Juan Basin of northwestern New Mexico and southwestern Colorado were discovered in a sub-pressured state, i.e., initial reservoir pore pressure was less than the hydrostatic head of fresh water. Due to variances in sub-interval permeability and drainage area extent, seventy plus years of sustained production and multiple infill campaigns have rendered the major producing intervals substantially differentially depleted on a layer by layer basis. Using the Equation 1, Figure 1 is provided to illustrate the magnitude of intra-formation layer reservoir pressure differences that have been measured in a single wellbore for four of the producing formation in the San Juan Basin.

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