Non-Darcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity

Abstract

Abstract The dramatic effects of non-Darcy and multiphase flow in propped hydraulic fractures have been documented by several authors.1,2,7,9-19 However, many engineers disregard these effects when designing fracture treatments under the assumption that they only apply to high rate wells. This paper shows these effects are significant even in wells considered to be low rate by current industry standards. Ignoring these effects will often lead to inaccurate production forecasts, suboptimal fracture design, and selection of an inappropriate proppant type. These mistakes result in lost revenues which can exceed $2 million per fracture treatment for typical gas and oil well fracture treatments conducted in North America. Proppant permeability values reported by the industry and used in most fracture design models are measured with a single-phase fluid at extremely low velocities. The laboratory rates stipulated in the American Petroleum Institute3 (API) Recommended Practice number 61 typically correspond to superficial fluid velocities ranging from 0.2 to 2.0 inches per minute. However, in real fractures, the actual fluid velocity may exceed two feet per second, approximately 1000 times greater than in the laboratory measurements. Although the API warned that the lab-measured values would not be realistic under actual fracture conditions, the industry has largely failed to incorporate correction factors into production models to compensate for non-Darcy flow effects. In addition to non-Darcy effects, the measured proppant permeability values fail to incorporate the effects of multiphase flow. Most gas wells will produce some free liquid (water or condensate), and almost all oil wells will be produced below the bubblepoint of the oil, resulting in substantial volumes of free gas in the fracture. This paper shows that non-Darcy and multiphase flow effects frequently result in an effective fracture conductivity 50% to 98% lower than the reference value obtained from the API testing procedure. Incremental reductions for gel damage and proppant embedment often result in fracture permeabilities or conductivities (the product of fracture permeability and effective fracture width) of 1 to 10% of the published values. This paper examines the mistakes that are likely to be made when ignoring these effects, and estimates the additional cashflow which can be obtained by optimizing fracture design with consideration of multiphase and non-Darcy flow.