Summary
Water-injection-induced fractures are key factors influencing successful
waterflooding projects. Controlling dynamic fracture growth can lead to largely
improved water-management strategies and, potentially, to increased oil
recovery and reduced operational costs (well-count and
water-treatment-facilities reduction), thereby enhancing the project
economics.
The primary tool that reservoir engineers require to guarantee an optimal
waterflood field implementation is an appropriate modeling tool, which is
capable of handling the dynamic fracturing process in complex reservoir
grids.
We have developed a new modeling strategy that combines fluid flow and
fracture growth in one reservoir simulation. Dynamic fractures are free to
propagate in length and height-direction with respect to poro- and
thermoelastic stresses acting on the fracture. A prototype simulator for
contained fractures was tested successfully.
We have extended the coupled simulator to incorporate noncontained
fractures. The new simulator, called FRAC-IT, handles fracture-length and
-height growth by evaluating a fracture-propagation criterion on the basis of a
Barenblatt (1962) condition. The solution of the 5D problem is computed by use
of a tuned Broyden (1965) approach.
We demonstrate the capabilities of the coupled simulator by showing its
application to a complex reservoir-simulation model. The fracture modeling is
used to history match an injectivity test in a five-spot injection pattern
using produced water. The coupled-simulation results and the field-data
interpretation show a very good match. The outcome of the injection test led to
an appropriate waterflood-management strategy adapted to the specific reservoir
conditions and, in terms of production, to a net oil-production increase of 50
to 100%. The field example shows how the coupled-simulator technology can be
used to achieve optimized waterflood-management strategies and increased oil
recovery.
Introduction
Waterflooding is often applied to increase the recovery of oil in mature
reservoirs or to maintain the reservoir pressure above bubblepoint in the case
of green fields. Even though often unnoticed, water injection frequently is
taking place under induced-fracturing conditions. The rock fracturing has a
strong influence on the water injectivity and the areal distribution of the
fluids in the reservoir. A qualitative example of the impact of the fracture
orientation on the areal sweep is demonstrated in Fig. 1. We show streamlines
in two different water-injection-pattern configurations for two fracture
orientations (i.e., line-drive and five-spot geometry, and fracture oriented
toward the producer and away from the producer. The density of the streamlines
indicates that the fracture orientation changes the areal sweep.
In order to achieve optimized water-injection management, dynamic fracture
propagation needs to be estimated properly before the injection, controlled
during operations, and monitored to ensure predictions and reality do not
deviate significantly.
The tools commonly used to study fracture growth numerically are analytical
fracture simulators, which often are based on a single-well model in a
simplified reservoir formation. Generally, reservoir heterogeneity is reduced
to a number of horizontal layers with homogeneous properties and a laterally
infinite extent. Fracture propagation is described using a pseudo-3D
description (van den Hoek et al. 1999). For many field developments under
waterflooding, fracture propagation is estimated with acceptable error bars
using these or similar tools. The major drawbacks are
- Areal reservoir heterogeneity is not accounted for.
- Varying poro- and thermoelastic stresses along the fracture are
neglected.
- Injection pressures have large error bars because the reservoir response is
not properly captured.
- Nearby well’s influences (e.g., pattern flood) are not captured.
In the past, many attempts have been made to address these issues. Common
approaches can be grouped into fully implicit simulators (Tran et al. 2002),
where both fluid-flow and geomechanical equations are solved simultaneously on
the same numerical grid, and coupled simulators (Clifford et al. 1991), where a
standard, finite-volume reservoir simulator is coupled to a
boundary-element-based fracture-propagation simulator. To our knowledge, both
approaches are not standard and currently not used in the industry because
- Models need to be purpose built (i.e., reservoir models from standard
reservoir simulator cannot be used).
- Fracture propagation is oversimplified.
- Numerical stability is questionable.
We have developed an extension to an existing reservoir simulator to
circumvent these shortcomings.
We use a coupled-simulator approach based on a two-way communication
strategy between the fully numerical reservoir simulator and the
half-analytical geomechnical-modeling part. The new simulator enables the
modeling of fluid flow and dynamic fracture propagation in a combined way.
We have applied the tool to field applications for waterflooding projects in
which injector/producer shortcuts are a potential risk (pattern floods) and
also to environments in which fracture containment and estimating accurate
injection pressures are the main concerns.
In this paper, we briefly review the coupled-simulator approach and discuss
the application to a waterflooding field example.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
28 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
14 May 2007
- Manuscript approved:
14 October 2007
- Version of record:
20 June 2008
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