In-Situ Diagnosis of Formation Characteristics in Horizontal Wells

Abstract

Summary A method is presented for estimating the distribution of a parameter related to the productivity index along the length of a liner-completed horizontal well, using measurements of well flowing pressure at multiple points along the path of flow in the wellbore. This is the concept of near-wellbore diagnosis with multipoint pressure measurements, which in principle can be made with fiberoptic sensors. The deployment mechanism of the sensors is not modeled in this study, although the temperature version of such sensors has been deployed in horizontal wells on an extended-tailpipe or stinger completion. (The temperature sensors also have been deployed in horizontal wells with sand-screen completions, in direct contact with the formation, but that configuration is not investigated in this study.) The parameter that is estimated is known in reservoirsimulation terminology as the connection factor (CF), which represents the hydraulic coupling or connectivity between the reservoir and the wellbore (between formation gridblocks and well segments). Parameter CF has units of md-ft, similar to flow capacity, or productivity index multiplied by viscosity. Specifically, the parameter is directly proportional to the geometric mean of the permeability perpendicular to the horizontal axis of the well and is inversely related to skin. No attempts are made in this study to estimate these parameters individually, which may require recourse to other methods of well diagnosis (e.g., dynamic formation testing, transient analysis, and production logging). The method applies to flow under constant-rate conditions and yields estimates of the CF, which represents the quality of the formation in the vicinity of the well and the integrity of the completion along the well trajectory. The quality of the inversion is determined by the spatial density and accuracy of the multipoint measurements. Inversion quality also depends on knowledge of the wellbore hydraulic characteristics and the relative permeability characteristics of the formation. The basic configuration investigated in this study consists of a five-node pressure array in a 2,000-ft horizontal well experiencing a total pressure drop of approximately 60 psi when produced at 10,000 STB/D. A reasonable estimate of the distribution of the parametric group CF is obtained even when allowing for measurement drift and errors in liner roughness and relative permeability exponent. Also, the inversion can be rendered insensitive to knowledge of the far-field permeability through a scaling technique. Therefore, good estimates of the near-wellbore CF profile can be obtained with uncertain knowledge of the reservoir permeability field. This is important because the technique can be applied not only to early-time but also to late-time data. The application of the multipoint pressure method is illustrated through a series of examples, and its potential for near-wellbore formation evaluation for horizontal wells is described.