UKH Journal of Science and Engineering | Volume 5 • Number 1 • 2021 120
source of such problems must be identified in order to apply effective and suitable techniques to control water
production (Gasbarri et al., 2007).
The cause of water coning is an imbalance between the viscous and gravitational forces around the completion interval.
In other words, the flow of oil from the reservoir to the well introduces an upward dynamic force upon the reservoir
fluids. This dynamic force is due to wellbore drawdown causes the water at the bottom of the oil later to rise to a certain
point at which the dynamic force is balanced, by the height of water beneath that point. Now as the lateral distance
from the wellbore increases, the pressure drawdown and the upward dynamic force decrease. Thus, the height of the
balance point decreases as the distance from the wellbore increase. Therefore, the locus of the balance point is a stable
cone shaped water oil interface. At this stable situation oil flows above the interface while water remains stationary
below the interface (Gasbarri et al., 2007).
This work addresses the water coning issues in a conventional and naturally fractured reservoir via a numerical
simulation approach on a single-well radial cross-section using commercial reservoir simulator (ECLIPSE 100).
Understanding the key parameters affecting water coning in both homogenous and heterogeneous reservoirs will lead
accurate identification of the problem and effective solution to mitigate or control the water production. This is an
effective production optimization approach for water producing reservoirs.
1.1. Coning Development
Producing oil from a well which is overlying water may cause the oil/water interface to deform into a bell shape. This
deformation is called water coning and occurs when the vertical component of the viscous force exceeds the net gravity
force (Hoyland et al., 1989). Therefore, two forces control the mechanism of water coning in oil and/or gas reservoirs:
dynamic viscous force and gravity force. Water coning phenomenon constitutes one of the most complex problems
pertaining to oil production (Saad et al., 1995). Coning phenomenon is more challenging in fractured reservoirs owing
to their heterogeneous and high permeable medium of the fractures compared to matrixes (Foroozesh et al., 2008). On
the other hand, water coning in naturally fractured reservoirs often result in excessive water production which can kill
a well or severely curtain its economics life due to water handling (Beattie & Roberts, 1996).
In the study of water coning phenomenon both in conventional and fractured reservoirs, three parameters are
determined: critical rate, breakthrough time and water cut performance after breakthrough. It is of essence to understand
the term critical rate. At a certain production rate, the water cone is stable with-it apex at a distance below the bottom
of the well, but an infinitesimal rate increase will cause instability and water breakthrough. This limiting rate is called the
critical rate for water coning (Hoyland et al., 1989). Therefore, critical rate is defined as the maximum allowable oil flow
rate that can be imposed on the well to avoid a cone breakthrough (Salavatov & Ghareeb, 2009).
In fractured reservoirs, critical rate is influenced by extra factors such as fracture storativity (ω), fracture transmissivity
(λ), fracture pattern and their interaction to matrixes; especially around the wellbore (Namani et al., 2007). Bahrami et
al. (2004) stated that because of heterogeneity and non-uniform fracture distribution in naturally fractured reservoirs,
the development of cone is asymmetrical, and estimation of critical rate and breakthrough time requires modelling with
an understanding of fracture pattern around the producing well.
These are the challenges of studying water in fractured reservoirs. In these reservoirs, the extent and stabilization of
cone growth depend on factors such as; oil zone thickness, mobility ratio, the extent of the well penetration and vertical
permeability; of which the most important parameter is the total production rate (Namani et al., 2007). Moreover, water
coning depends on the properties of the porous media, distance from the oil-water interface to the well, oil-water
viscosity ratio, production rate, densities of the fluids and capillary effects. Conversely, in fractured reservoirs this
problem is more complicated because of the dual porosity system in the fractured reservoir which results in formation
of two cones (i.e., coning in the fracture and matrix). Depending on the rates, a fast-moving cone may be developing in
the fracture whilst a slow-moving cone is observed in the matrix. The relative position of the two cones is rate sensitive
and is a function of reservoir properties (Al-Aflagh & Ershaghi, 1993). The key parameter in determining water coning
tendency is the vertical to horizontal permeability ratio, kv/kh. The existence of natural fractures however often results
in high values of kv/kh providing conditions conducive to water coning (Beattie & Roberts, 1996). Therefore, high
vertical permeability in fractures is bound to accelerate the coning process resulting in lowering of the critical rates and
more rapid breakthrough times. In addition, the favored path for fluid flow through the fractures and the uneven fracture
conductivities commonly observed in naturally fractured reservoirs is expected to affect wells regardless of their
structural position (Al-Aflagh & Ershaghi, 1993). Understanding the effect of various rock and fluid properties such as