Summary
Tight gas carbonate fields are often faced with early water breakthrough in
the presence of fractures connected with an active aquifer. The recovery
assessment from such fields requires us to take into account the role played by
water imbibition of the matrix, which, depending on the fracture density and
rock properties, can delay water breakthrough significantly. The prediction of
such spontaneous-imbibition phenomena requires experimental measurements and
modeling in the case of rocks of complex porous structure like vuggy
carbonates. This paper gives the results of such an investigation on samples
from a vuggy carbonate field. A thorough petrophysical characterization of the
rock was carried out first, followed by water/gas imbibition experiments. Those
experiments were finally simulated numerically to check the consistency of the
experimental data set and further understand the fluid-flow behavior of those
peculiar media.
The porous structure of several samples was characterized from capillary
pressure and nuclear magnetic resonance (NMR) measurements. Spontaneous
imbibition was found to be very slow, which required the implementation of a
specific accurate measurement device. The slow kinetics was caused by the very
low mobility of water, which was measured separately as well. To explain this
flow behavior, the peculiarity of the porous structure of the rock-type
studied—fairly large vugs dispersed within a tight matrix with very small pore
thresholds—is invoked. Simulations on a representative pore-network model
actually revealed that the flow ability of the water phase is considerably
hindered in such a medium. Finally, the spontaneous-imbibition behavior was
reproduced satisfactorily with single-porosity and dual-porosity models using
the measured petrophysical parameters, thus showing the consistency of the
measured data set.
Gas-production management from vuggy carbonate reservoirs subjected to water
encroachment requires a specific evaluation of matrix-imbibition phenomenon
because the latter is ruled by unconventional flow parameters linked to the
complex two-phase-flow interactions between vugs and micropores in such
media.
Introduction
Significant gas reserves are contained in fractured vuggy carbonate
reservoirs, which may be faced with early water production leading to well
shut-in and low gas recovery. Several of these fractured carbonate gas fields
are located in the foothills of the Rocky Mountains, with volumes in place
exceeding 1 Tcf for the largest ones (Hnatiuk 1970; Davidson and Snowdon 1978;
Thomas et al. 1996).
Reservoirs consist of tight dolomitized carbonates with a permeability
generally less than 1 md. Fractures provide the main contribution to well
productivities but are responsible for matrix gas bypassing and early water
breakthroughs leading to premature well shut-in. Hence, most of these fields
have now reached the phase of abandonment with abnormally low gas-recovery
factors.
The key point in the understanding of these reservoirs is the natural water
imbibition of the matrix that occurs with the fracture-network invasion by
water. This natural imbibition plays a major role in the water breakthrough
time prediction at the producers and also in the final gas-recovery estimation.
This paper is a contribution to the understanding of these mechanisms in vuggy
carbonate reservoirs, where the complex pore structure (vugs) can affect the
production kinetics and the recovery from the matrix. The selected approach
consists in first performing and analyzing laboratory experiments of natural
imbibition mechanisms on representative core samples, then deriving the
parameters involved from the numerical simulation of these experiments.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
9 January 2004
- Meeting paper published:
17 April 2004
- Revised manuscript received:
9 August 2006
- Manuscript approved:
10 October 2006
- Version of record:
20 February 2007
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