Flow distribution plays an important role in Produced Water Re-Injection operations. This is especially true when the injection horizon contains isolated hydraulic units that are individually capable of accepting part of or the entire injection rate. The hydraulic units maybe separated by an impermeable barrier, shale, and/or have variations in the minimum horizontal stress. Under normal operating conditions fractures initiated in one or more of these units would not intersect or combine. The fracture growth becomes a coupled problem where growth in one hydraulic units is dependent on growth or retardation in other units. Retardation might be caused by solid and oil deposition in the fracture that would plug its tip and damage its faces. Plugging would decrease available fracture length for leakoff below the actual total length of the fracture. Such scenarios become difficult to control if not initially planned or designed for and can lead to undesirable effects such as inefficient sweep or uncontrolled fracture growth.

In the following discussion the design and monitoring criteria for such problems will be addressed. We will review some available tools and prominent parameters and/or variables that affect this behavior both from a time dependent and independent point of view. Particular attention will be placed on the damage mechanisms, total suspended solids (TSS) and oil in water (OIW), and their effects on altering the injection rate distribution as a progressive time dependent phenomena.

Finally, two scenarios will be presented, as practical examples of field cases where flow partitioning issues presented a particular concern as a result of inherent reservoir properties.


The main goals of Produced Water Re-Injection[1–3] (PWRI) during water flooding are reservoir pressure support or maintenance by voidage replacement and improving the formation fluid sweep efficiency. In addition, the disposal of significant volumes of contaminants namely the suspended solids and OIW is a side benefit. It has been widely accepted by the industry that successful waterflooding occurs under fracturing conditions. The successful performance of an injection well depends upon lon-term maintenance of injectivity into the appropriate hydraulic units.

Waterflood models have been presented to predict the performance of injection operations1. Perforation schemes have been used to control the production and injection profiles in horizontal wells[2]. However, most often the injection horizon within the reservoir may be composed of a number of geomechanically independent hydraulic units. The initiation and propagation of fractures in the hydraulic units and the subsequent injection profile over the injection horizon depends upon the rock mechanical and formation flow properties. With no external intervention, the initial distribution of injection fluids in the well depends on the formation kh (md-ft) and the stress. The presence of solid particles and oil droplets in the injection water initiates formation and fracture damage in the hydraulic units which in some cases could lead to plugging and loss of injectivity. This injectivity loss in one hydraulic unit alters the injection profile in the reservoir so that other units receive more wellhead fluids which in turn could impact the desired voidage replacement and sweep efficiency.

The following sections of this paper present a mechanism to track the distribution of injection fluids between various hydraulic units. A number of factors are involved in achieving downhole flow conformance and fluid distribution. The main variables considered in this analysis are the formation permeability, unit thickness, horizontal stresses, injection water temperature, number of perforations, and the effect of any downhole flow control devices. Case studies illustrate the applicability of the method in the design and planning of injection wells with distinct hydraulic injection units.

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