The Impact of Non-Darcy Flow on Production from Hydraulically Fractured Gas Wells (2001)

The Impact of Non-Darcy Flow on Production from Hydraulically Fractured Gas Wells Patrick Handren; Patrick Handren CARBO Ceramics, Inc. Search for other works by this author on: This Site Google Scholar C. Mark Pearson; C. Mark Pearson CARBO Ceramics, Inc. Search for other works by this author on: This Site Google Scholar John Kullman; John Kullman CARBO Ceramics, Inc. Search for other works by this author on: This Site Google Scholar Robert J. Coleman; Robert J. Coleman Chevron USA Production Company Search for other works by this author on: This Site Google Scholar Jay Foreman; Jay Foreman Halliburton Energy Services Search for other works by this author on: This Site Google Scholar Keith Froebel; Keith Froebel Total-Fina-Elf Search for other works by this author on: This Site Google Scholar Jon Caron Jon Caron Total-Fina-Elf Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, March 2001. Paper Number: SPE-67299-MS https://doi.org/10.2118/67299-MS Published: March 24 2001 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Handren, Patrick, Pearson, C. Mark, Kullman, John, Coleman, Robert J., Foreman, Jay, Froebel, Keith, and Jon Caron. "The Impact of Non-Darcy Flow on Production from Hydraulically Fractured Gas Wells." Paper presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, March 2001. doi: https://doi.org/10.2118/67299-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Oklahoma City Oil and Gas Symposium / Production and Operations Symposium Search Advanced Search AbstractThe pressure drop due to flow within a propped fracture results from three mechanisms: viscous drag of the fluid, inertial effects associated with the movement of fluid around the proppant grains, and multiphase effects associated with the interaction of the different fluid phases.Most existing fracture models and production simulators analyze the effects of viscous drag only, often underestimating the total pressure drop in the fracture by one or two orders of magnitude. These models rely solely on the reference permeability of the proppant, which is measured in the laboratory with extremely low flow rates of 2 to 10 cc/min. This paper reviews the design changes necessary to accommodate the incremental pressure losses resulting from multiphase and non-Darcy flow, and shows application of the theory to two operators' stimulation programs.Production rate projections and economic analyses are provided for fracture treatments conducted in two field programs (both gas reservoirs): Total-Fina-Elf's development in the Frio and Vicksburg reservoirs of South Texas and Chevron USA's Birch Creek Unit in the Green River Basin of Wyoming.Fracture treatments in existing wells had been designed with traditional Darcy flow models. New stimulation treatments were redesigned to include multiphase and non-Darcy flow effects. This paper provides details of the two different stimulation treatment designs in each of the development programs and the production results - average productivity increases of 20 to 30% for the new wells compared to offset wells treated with stimulations based on Darcy flow design models.IntroductionThe American Petroleum Institute has published standard testing procedures1 which involve flowing a single phase liquid (water with 2% KCl) through a 7" × 11/2" linear proppant pack cell at flowrates of 2 to 10 ml/min. The superficial velocity of the water during the test is on the order of 0.2 to 2.0 inches per minute; while in actual fractures, the true fluid velocity can be several feet per second. The conductivity tests were designed for operational simplicity and selected to be in the laminar flow regime to improve repeatability.Proppant suppliers in the industry have used modified API procedures to publish long-term permeability values for their products. Many engineers have used these reference values in fracture design without making appropriate adjustments for the non-Darcy and mutiphase flow effects that occur once the well has been placed on production. Erroneously using the published proppant permeability values without compensation for non-Darcy and multiphase flow effects results in:Invalid fracture conductivity predictions - which may be overestimated by more than an order of magnitude,Design of a sub-optimal stimulation treatment including a shorter effective producing fracture half-length,Significant overestimation of the post-stimulation production rates,Potential for selection of the incorrect proppant for the fracture treatment design,Significant loss in production from the fractured well compared to what could have been achieved, andA reduction in recoverable reserves. Keywords: conductivity, production model, multiphase, fluid velocity, non-darcy flow, hydraulically fractured gas well, flow in porous media, permeability, fracturing materials, forchheimer Subjects: Hydraulic Fracturing, Reservoir Fluid Dynamics, Fracturing materials (fluids, proppant), Flow in porous media This content is only available via PDF. 2001. Society of Petroleum Engineers You can access this article if you purchase or spend a download.