86
The Chemistry and Technology of Petroleum
tests and precise measurement techniques to capture the complex phase behavior exhibited by these
fluids. Gas condensates in the presence of water require PVT cells that can handle three-phase mixtures of gas, water, and condensate.
A heavy oil sampling program requires extra steps to obtain adequate volumes of representative
single-phase oil samples for laboratory analysis. This includes adequate near-wellbore cleaning to
minimize sample contamination by drilling-mud filtrate and optimal drawdown to minimize sand
production and avoid two-phase flow while mobilizing the oil from the reservoir into the sample
chamber (Reddie and Robertson, 2004). During surface sampling, measurement uncertainty in the
producing GOR is a concern because of large drawdown and incomplete gas separation from the
oil. Another issue with surface samples is the slow dissolution of gas while recombining them to
prepare reservoir fluid.
The main advantage of bottomhole sampling over surface sampling is that the former offers a
viable means to capture single-phase samples and eliminate uncertainties associated with surface
samples.
The C7+ fraction of the reservoir fluid contains numerous compounds of different homologues
(paraffinic, naphthenic, and aromatic) and plays a dominant role in determining the PVT behavior
of the fluid. For example, in a gas-condensate fluid, the dew point pressure is (as anticipated) a
strong function of C7+ molecular weight and its relative amount in the fluid. On the other hand, in
heavy oils, the C7+ components dictate the viscosity behavior and control the asphaltene deposition
and wax deposition characteristics of the oil. Similarly, in volatile oils and rich condensates, the
oil volumes and other properties below the saturation pressure are determined by the amounts of
intermediate and heavy components.
Therefore, it is important to characterize them accurately and several methods are used to lump
these components into pseudo-components for equation-of-state models (Whitson, 1983) in which
the C7+ distribution is represented by a continuous gamma distribution that is optimally discretized
into a specific number of fractions (i.e., pseudo-components) in which fluid type and the production
process involved further guides the component selection.
Because of slow gas liberation and dissolution in heavy oil, special care should be exercised in
selecting equipment and procedures for sample preparation and PVT measurements (Cengiz et al.,
2004). It is essential to measure the true bubble point pressure as well as the viscosity by means of,
for example, a capillary-flow viscometer. Because the oil is saturated at each pressure step in the
differential-liberation experiment, small pressure drops in the capillary viscometer caused by the
flow will liberate the gas. Therefore, it may be necessary to conduct several viscosity measurements
above the saturated pressure and use an extrapolation technique to determine the viscosity at the
desired differential-liberation pressure.
PVT-data interpretation and modeling for heavy oils require reliable treatment of C7+ components because a majority of components in heavy oils fall in this range (Ancheyta and Speight,
2007). Solid-forming compounds, such as resin constituents and asphaltene constituents, should be
characterized properly for flow assurance needs.
Thus, it is imperative that reservoir fluid characterization studies should relate where possible,
considering the nature of heavy oil, to the following issues: (1) acquisition of representative samples
at various depths to quantify initial fluid gradients and for PVT studies; (2) PVT measurements to
capture near-critical behavior, evaluate gas-injection strategies, and design the surface-separator
train; (3) fluid modeling to predict observed near-critical behavior and property changes during gas
injection; and (4) development of thermodynamically consistent compositional-gradient models for
use in reservoir studies.
Fluid characterization strongly affects in-place-volume, recovery-factor, injectivity/productivity,
and well-deliverability calculations. Accurate fluid characterization minimizes technical uncertainties and, thus, provides a reliable representation of the asset value. However, fluid-sampling programs must be tailored to the fluid type, reservoir-rock and -fluid conditions, and fluid distribution.
The fluid type and production processes dictate PVT data requirements, measurement methods, and
The Chemistry and Technology of Petroleum
tests and precise measurement techniques to capture the complex phase behavior exhibited by these
fluids. Gas condensates in the presence of water require PVT cells that can handle three-phase mixtures of gas, water, and condensate.
A heavy oil sampling program requires extra steps to obtain adequate volumes of representative
single-phase oil samples for laboratory analysis. This includes adequate near-wellbore cleaning to
minimize sample contamination by drilling-mud filtrate and optimal drawdown to minimize sand
production and avoid two-phase flow while mobilizing the oil from the reservoir into the sample
chamber (Reddie and Robertson, 2004). During surface sampling, measurement uncertainty in the
producing GOR is a concern because of large drawdown and incomplete gas separation from the
oil. Another issue with surface samples is the slow dissolution of gas while recombining them to
prepare reservoir fluid.
The main advantage of bottomhole sampling over surface sampling is that the former offers a
viable means to capture single-phase samples and eliminate uncertainties associated with surface
samples.
The C7+ fraction of the reservoir fluid contains numerous compounds of different homologues
(paraffinic, naphthenic, and aromatic) and plays a dominant role in determining the PVT behavior
of the fluid. For example, in a gas-condensate fluid, the dew point pressure is (as anticipated) a
strong function of C7+ molecular weight and its relative amount in the fluid. On the other hand, in
heavy oils, the C7+ components dictate the viscosity behavior and control the asphaltene deposition
and wax deposition characteristics of the oil. Similarly, in volatile oils and rich condensates, the
oil volumes and other properties below the saturation pressure are determined by the amounts of
intermediate and heavy components.
Therefore, it is important to characterize them accurately and several methods are used to lump
these components into pseudo-components for equation-of-state models (Whitson, 1983) in which
the C7+ distribution is represented by a continuous gamma distribution that is optimally discretized
into a specific number of fractions (i.e., pseudo-components) in which fluid type and the production
process involved further guides the component selection.
Because of slow gas liberation and dissolution in heavy oil, special care should be exercised in
selecting equipment and procedures for sample preparation and PVT measurements (Cengiz et al.,
2004). It is essential to measure the true bubble point pressure as well as the viscosity by means of,
for example, a capillary-flow viscometer. Because the oil is saturated at each pressure step in the
differential-liberation experiment, small pressure drops in the capillary viscometer caused by the
flow will liberate the gas. Therefore, it may be necessary to conduct several viscosity measurements
above the saturated pressure and use an extrapolation technique to determine the viscosity at the
desired differential-liberation pressure.
PVT-data interpretation and modeling for heavy oils require reliable treatment of C7+ components because a majority of components in heavy oils fall in this range (Ancheyta and Speight,
2007). Solid-forming compounds, such as resin constituents and asphaltene constituents, should be
characterized properly for flow assurance needs.
Thus, it is imperative that reservoir fluid characterization studies should relate where possible,
considering the nature of heavy oil, to the following issues: (1) acquisition of representative samples
at various depths to quantify initial fluid gradients and for PVT studies; (2) PVT measurements to
capture near-critical behavior, evaluate gas-injection strategies, and design the surface-separator
train; (3) fluid modeling to predict observed near-critical behavior and property changes during gas
injection; and (4) development of thermodynamically consistent compositional-gradient models for
use in reservoir studies.
Fluid characterization strongly affects in-place-volume, recovery-factor, injectivity/productivity,
and well-deliverability calculations. Accurate fluid characterization minimizes technical uncertainties and, thus, provides a reliable representation of the asset value. However, fluid-sampling programs must be tailored to the fluid type, reservoir-rock and -fluid conditions, and fluid distribution.
The fluid type and production processes dictate PVT data requirements, measurement methods, and