Summary
Two-dimensional (2D) NMR techniques have been proposed as efficient methods
to infer a variety of petrophysical parameters, including mixed fluid
saturation, in-situ oil viscosity, wettability, and pore structure. However, no
study has been presented to quantify the petrophysical limitations of such
methods. We address this problem by introducing a pore-scale framework to
accurately simulate suites of NMR measurements acquired in complex rock/fluid
models. The general pore-scale framework considered in this paper is based on
NMR random walks for multiphase fluid diffusion and relaxations, combined with
Kovscek’s pore-scale model for two-phase fluid saturation and wettability
alteration. We use standard 2D NMR methods to interpret synthetic data sets for
diverse petrophysical configurations, including two-phase saturations with
different oil grades, mixed wettability, or carbonate pore heterogeneity.
Results from our study indicate that for both water-wet and mixed-wet rocks,
T2 (transverse relaxation)/D (diffusion) maps are
reliable for fluid typing without the need for independently determined
cutoffs. However, significant uncertainty exists in the estimation of fluid
type, wettability, and pore structure with 2D NMR methods in cases of
mixed-wettability states. Only light oil wettability can be reliably detected
with 2D NMR interpretation methods. Diffusion coupling in carbonate rocks
introduces additional problems that cannot be circumvented with current 2D NMR
techniques.
Introduction
Wettability state and oil viscosity can play a significant role in the NMR
response of saturated rocks. This property of NMR measurements has been
discussed in recent papers (Freedman et al. 2003) for particular examples of
rock systems. However, to date, no systematic study has been published of the
reliability and accuracy of NMR methods to assess fluid viscosity and
wettability, including cases of mixed wettability. This paper quantifies the
sensitivity of 2D relaxation/diffusion NMR techniques to mixed wettability and
fluid viscosity in generic rock models.
Given that measurements are often made on rock samples with uncertain
petrophysical properties and therefore uncertain corresponding measurement
contributions, the work described in this paper is based on the numerical
simulation of pore-scale systems. We introduce a general numerical model that
simultaneously includes immiscible fluid viscosities, water or mixed
wettability, variable fluid saturations and history, and disordered complexity
of rock structure. Geometrical fluid distributions at the pore scale were
considered a function of pore size, saturation history, and wettability
following Kovscek et al.’s model of mixed-oil-wet rocks (1993). We simulated
suites of NMR measurements with random walkers within these pore-scale
geometries, and subsequently inverted into relaxation/diffusion NMR maps. The
objective of this paper is to assess the accuracy of 2D NMR interpretation
techniques to detect fluid and wettability types, and to quantify pore-size
distributions.
The first section of the paper summarizes the principles and limitations of
current NMR petrophysical interpretation. We then summarize our pore-scale
modeling procedure, its assumptions, and limitations. Subsequent sections
analyze simulation results obtained for drainage and imbibition involving
water-wettability and mixed-oil-wettability with partial saturations of water
and different hydrocarbon types in a generic clay-free rock model. Next, we
consider the case of coupled carbonate rocks with emphasis on the assessment of
wettability and microporosity.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
5 September 2004
- Revised manuscript received:
17 March 2006
- Manuscript approved:
27 March 2006
- Version of record:
20 September 2006
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