Summary
Foams have been widely used to control fluid mobility in improved oil
recovery as well as in near-wellbore production enhancement operations, such as
acid diversion. The efficiency of fluid blockage and diversion depends strongly
on the geological layering of the formation and on the occurrence of (viscous
and capillary) crossflow. However, these effects have not been studied in
detail in the literature. In this paper, we report an experimental study of
foam-induced fluid diversion in isolated and capillary-communicating
double-layer cores. Sodium dodecyl sulfate (SDS) surfactant was used at just
above its critical micelle concentration. Natural rocks were used to
manufacture concentric double-layer cores, having final permeability contrasts
in the range of 10 to 200. We also used capillary-communicating double-layer
cores, obtained by sintering two homogeneous glass-bead layers. In addition to
pressure-drop monitoring, the in-situ fluid saturation was visualized using
X-ray computerized tomography. A range of foam qualities has been
investigated.
Introduction
The purpose of matrix acidizing is to remove formation permeability
reduction near the wellbore (damage) by enlarging pore spaces and dissolving
particles plugging these spaces. In stratified formations with damaged
intervals distributed along the wellbore, the acidizing treatment often results
in acid loss into nondamaged zones (high permeability), leading to a nonuniform
injection profile. Several diversion techniques have been developed to improve
the efficiency of acid placement, such as mechanical (straddle packer or ball
sealers) or chemical (viscous fluids, particulate diverters). Among the latter,
surfactant stabilized foam offers distinct technical, economical, and
environmental advantages.1–6 A typical process of foam-diverted acidizing
includes two stages. In the first stage, foam is placed in high-permeability
layers (foam placement). Then in the second stage, the injection of acid starts
and the foam is expected to divert acid into low-permeability layers (fluid
diversion). Beside fluid rates and physicochemical properties of foam, the
extent of capillary communication between layers of contrasting permeabilities
has significant influence on macroscopic foam behavior in both stages.
Investigating foam propagation in two isolated parallel Berea sandstone
cores with permeability contrast of approximately 5, Llave et al.7 observed a
strong development of foam in the high-permeability core, resulting in foam
diversion into the low-permeability one. For lower-permeability contrast
ranging from 0.37 to 3.7 and high surfactant concentration, Yaghoobi et al.8,9
reported that foam developed rather uniformly throughout a composite core the
two concentric layers of which were in capillary contact. In these studies, the
relative foam propagation rates in layers were interpreted from the
pressure-drop profile and the effluent foam quality. Recently, Bertin10 used
the X-ray Computed Tomography (CT) technique to visualize the in-situ transient
foam displacement in composite cores with a high-permeability contrast of
approximately 67. With crossflow, their results show a uniform foam propagation
over the core. However, if the crossflow is prohibited, the foam front
traverses faster the low-permeability layer (LPL). Bertin et al.11 explained
the latter on basis of capillary pressure-controlled foam stability. Kovscek
and Bertin12 later reported that foam could strongly block the
high-permeability layer (HPL) if its liquid fraction is sufficiently in this
layer. Rossen13 and later Tanzil et al.14 proved theoretically that foam
generation is promoted as gas flows from low permeability to high
permeability.
Most of the previous experimental studies on the (acid) fluid-diversion
stage were restricted to parallel flow configuration by using a dual-core
flooding setup without any crossflow between the two cores. Burman and Hall4
reported that 74%-quality foam could divert 20% salt solution injected after
foam to a low-permeability core, for permeability contrasts ranging from 1.6 to
3.8. Diversion efficiency has also been found to increase with foam quality.
However, Thompson and Gdanski15 observed longer acid diversion with higher foam
quality for very low-permeability limestone cores. Bernadiner et al.16 also
proposed the use of foamed acid to obtain stimulation deeper from the wellbore.
Zerhboub et al.17 and later Parlar et al.18 reported a strong effect of foam
slug size and shut-in period between foam placement and fluid injection stages
on diversion efficiency. The effect of the system pressure was also highlighted
by Siddiqui et al.19 The work of Behenna20 showed an extreme case in which the
damaged layer to be stimulated has permeability of 0.28 md, allowing nearly no
invasion of foam. The main conclusion from this study is that the less foam
penetrating into an LPL, the higher the diversion capacity.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
12 August 2003
- Revised manuscript received:
23 August 2004
- Manuscript approved:
18 January 2005
- Version of record:
15 March 2005
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