The process ofinjecti1lg water above the fracture opening and closing pressure (Pfoc) has enjoyed liberal use and abuse. Since injection above (Pfoc) is rarely designed for, it has received little attention from a modelling perspective. Recent interest, particularly in the North Sea in the design and implementation of pressure induced fracturing, has resulted in a series of numerical simulation studies that investigate this process in detail. The work has identified both pros and cons for pressure induced fracturing. Water flood projects can benefit from increased injectivity improved frontal contact area and increased producer to injector ratios, all of which can lead to improved economics. Potential pitfalls include reduced areal sweep efficiency, loss of injected fluids to up/downhole thief zones and wellbore failure due to altered stress states. This paper describes the techniques used to analyse lab data and field tests that can be used to help design and evaluate pressure induced fracturing. Both numerical modelling and field examples will be used to demonstrate the factors controlling fracture geometry, growth rates likelihood of length stabilization and more.


Injection of fluid under fracturing conditions occurs when the bottomhole pressure exceeds the fracturing opening and closing pressure. This situation has been traditionally avoided for fear of opening a fracture that could result in either a loss of injected fluids to another formation or generation of a fracture which, due to excessive length, could result in a loss of sweep efficiency and hydrocarbon recovery. The deliberate operation of injectors above Pfoc is rare and the modelling of the consequences even less common. Injection of low viscosity fluids, such as water, differs dramatically from traditional high viscosity fracture completion fluids, due to higher leak-off rates encountered in the case of water injection.

Recent work in the North Sea has led to a new understanding of waterflood pressure induced fracturing and modelling techniques that can be used to predict fracture growth rates and geometries. Knowledge of such behavior can be used to the economic benefit of the operator by reducing the number of injectors required and by increasing recovery via contact of additional reserves.

Due to the many parameters controlling fracture propagation, the evaluation of the problem is complex. A systematic evaluation of field tests, combined with numerical modeling can be used to quantify dominating parameters. This paper describes the nature of the problem and procedures which can be used to design for waterflooding above Pfoc

Nature of the problem

Since the fracturing industry is fraught with conflicting terminology the following brief review is warranted:

Equations (available in full paper)

The fracture propagation pressure (FPP) is the bottomhole pressure at the well under fracturing conditions. The minimum horizontal stress (σ H) is the initial confining stress exerted on a vertical fracture. The orientation of σ H detennines the fracture orientatlon (perpendicular to σ H). Values for σ H range typically between 14.7 and 21.5 kPa/m of depth (0.65 and 0.95 psi/ft) for vertical fractures.

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