Net Pressure Trends: Is it Permeability, Complexity or just Fluid Response?: A Workflow To Determine Stimulation Effectiveness in Naturally Fractured and Matrix-Based Permeability Reservoirs

Abstract

Hydraulic fracturing stimulation in unconventional reservoirs has taken on a new emphasis in the search for oil and liquids from these low permeability reservoirs. Today, we are attempting to achieve economic production from reservoirs that were passed over just five years ago. The fracture stimulation goal: to provide a conductive path between the reservoir and the wellbore. However, these reservoirs are inherently difficult, at best, to evaluate and to fully understand the completion environment at a distance from the wellbore. Fortunately, there is a workflow that allows understanding of permeability sources as the fracture treatment is placed in real time and certainly in post-frac analysis. The toolbox uses a "planar" frac model to analyze data gathered from surface sources. This paper will discuss a workflow to differentiate between pressure trends due to fluid and/or proppant effects on friction, and actual net-pressure change due to permeability exposure by the frac fluid in the reservoir. By understanding that fracture stimulation is a highly invasive process, the authors will examine the data that can be used as a benchmarking tool for reservoir response. We will discuss examples from the Eagle Ford formation for naturally fractured permeability reservoirs and the Wolfberry trend for matrix-based reservoirs. The workflow will aid in fracture spacing in horizontal wells and well spacing in multi-layered vertical wells.

Slip-corrected liquid permeability and its effect on hydraulic fracturing and fluid loss in shale

“…Our results are reasonable because high apparent fracture toughness (causing shorter fractures and higher injection pressure than expected) is common in field data [31][32][33]. The injection pressure fluctuated and showed a general upward trend, features that are commonly observed during formation of a ''complex" fracture network [34]. Fig.…”

Optimizing Hydraulic Fracture Performance in the Liquids-Rich Eagle Ford Shale - How Much Proppant Is Enough?

“…These results suggest that the predominant fracture failure mode in this environment is planar, rather than complex, fracturing, which has been verified by fracture net pressure-matching performed in various regions of the Eagle Ford. Lehman et al (2013) presented a couple of examples of net pressure-matching Eagle Ford stimulation data, and noted that any complexity observed usually occurs early in the treatment and likely exists at near-wellbore distances.…”