Rewards & Pitfalls of Using Treating Pressure Analysis for Evaluating Fracture Design
Authors: Cramer David D. 
Published: December 2007

Analyzing pressures during a fracture treatment provides insight into the hydraulic fracturing process, and is widely used today. In this paper case histories are reviewed and guidelines are presented to identify pitfalls and establish strategies in pressure-analysis methods and procedures.

Introduction

Analyzing pressures during and immediately after the treatment of a well can provide insight into the hydraulic fracturing process and the effectiveness of stimulation job design. The parameters affecting treating pressure are hydrostatic head, friction pressure (drag force when injecting fluid or slurry into the well), and rock properties and in-situ stresses. Treatment pressure can be dissected into a series of systems or nodes: well tubulars "near-wellbore" area, and far-field fracture(s). Well tubulars include all piping (e.g., treating lines, tubing, casing/open hole, annulus) between the pressure transducer at the surface (the normal point of pressure measurement) and the perforations. The near-well bore area can be thought of as a process zone; it includes perforation orifices in the casing, and the connection between perforations and far-field fracture(s); this connection is often via the initially-narrow casing/hole annulus perimeter and sometimes may include a tortuosity component due to near-wellbore (e.g., several wellbore diameters) fracture turning and multiple-fracture strands. In-situ stresses may affect the process zone to some degree. The far-field fracture(s) is the main body of the fracture, downstream of the process zone. In-situ stresses, mechanical rock properties, and rock discontinuities mainly determine the pressure inside the fracture. Pressure drops or variances within the fracture can be significant when flow velocity is high. such as with narrow-width fractures or where a restriction (e.g., proppant bridge) exists.

It's important to dissect the various components of hydrostatic head and pressure drop to arrive at the desired endpoint, the pressure within the far-field fracture, so that the achieved fracture geometry and proppant placement can be inferred by pressure analysis. This is often not an easy task as the drag resistance of fracturing fluids can be affected by small variances in tubular wall roughness, additive concentrations (e.g., crosslinker, polymer, buffer), fracturing-fluid temperature, and proppant concentration.

With the commercial availability of hydraulic fracture-growth simulators that allow comparison ("matching") of measured and simulated pressures during ("real-time") and after the treatment, practitioners of treating-pressure analysis have greatly increased in number. Often, contrasting interpretations are derived by different practitioners using very similar, or the same, data-sets and simulators. This disparity can be confusing to the well-operator. At stake is the productivity of the well and profitability of the treatment investment.

Historical review

Modern-day evaluation of fracturing treating pressures started in 1979 with the work of Nolte and Smith.

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