Relative Permeability in Hydrocarbon Reservoirs: Analysis and Methods

This report provides a comprehensive overview of relative permeability in hydrocarbon reservoirs, emphasizing its critical role in multi-fluid flow and its impact on oil recovery. It discusses the significance of relative permeability in delaying water breakthrough and reducing operational costs. The report details various measurement techniques, including steady-state and unsteady-state methods, along with empirical and numerical approaches. It highlights the application of Darcy's law, the use of IMPES numerical models for core analysis, and the influence of capillary pressure. Furthermore, the report covers the importance of laboratory data and simulation methods for determining relative permeability curves, while also acknowledging the limitations of these techniques and recommending laboratory measurements under reservoir conditions. The report also includes references to relevant research papers and publications.

RELATIVE PERMEABITY
Importance of relative permeability
In hydrocarbon reservoirs, the flow of fluids involves multi-fluids, each of which has its own
permeability. The permeability of a particular fluid is minimized by the presence of the other
liquids and or gases in the voids. The flow of the multi-phased system is best described using
relative permeability; relative permeability described as the ratio of effective permeability of a
fluid to the absolute permeability of a rock.
k ri=k i
k
Relative permeability is depended on by water breakthrough. In heavy oil production, water
breakthrough is a huge challenge which causes increased water cut during the production
process. However, if water breakthrough is delayed, it increases the volume of pure oils
produced and also reduces the operational and maintenance costs (Ediriweera & Halvorsen,
2015). Therefore, manipulating relative permeability; through oil recovery methods; will delay
water break through.
Measurement of relativity permeability
Relative permeability can be determined using laboratory techniques; steady and unsteady state
techniques; and also, empirical techniques and also calculations from field data (Honarpour &
Mahmood, 1988).
The steady state system utilizes Darcy's law and gives the most dependable relative permeability
data ("5. Measurement of Relative Permeability | Global CCS Institute", 2018). In this strategy, a
few fluids are injected at the same time at the same rates or pressure for stretched out spans to
achieve equilibrium. Parameters such as flow rates, saturation, pressure are estimated and
utilized as a part of Darcy's law to acquire the effective permeability for every stage and in thus
relative permeability. Changes in saturation are controlled to be unidirectional (i.e., imbibition or
drainage) so that hysteresis can be prevented.
Unsteady-State Techniques maybe the fastest strategies for getting relative permeability in the
laboratory. In these procedures, saturation equilibrium isn't accomplished; hence, a batch of
relative-permeability versus saturation curves can be acquired within a couple of hours.
Typically, it includes displacing on site fluids by constant-rate or pressure, then a driving fluid is
injected while observing the effluent volumes consistently. Analysis of the production data is
done; a set of relative-permeability curves is obtained using various mathematical methods.
Experimental Technique models are now and then used to estimate relative permeability due to
the huddles involved in measurement. Limited laboratory data may be extrapolated using these
models. The porous medium h’s been idealized as a bundle of capillaries in several proposed
predictive models. The flow via a single capillary is portrayed numerically, thereafter, the
volume through the entire set of capillaries is obtained using the idea of capillary pressure.
Mathematical methods have likewise been utilized to portray irregularity of pore-size
distribution in a porous media.
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Relative permeability might be established from the production history of a reservoir and its gas
and liquid properties. In this method, relative-permeability computations require complete
production history data and average values affected by saturation gradients and pressure will be
given, in addition, contrasts in phases of depletion, and saturation variations in stratified
reservoirs will also be given. A different potential technique for determining on site effective
permeability is the pressure-transient testing which is used in besides accurate downhole flow-
measurement instruments.
How numerical methods is used to characterize the relative
permeability for the core
Relative permeability can be gotten from laboratory data obtained from core flooding
experiments. This data may be analyzed using numerical or analytical methods (Hou et al.,
2012).
The numerical models may use an Implicit Pressure and Explicit Saturation (IMPES) technique
which has been produced to numerically simulate two phase immiscible, incompressible, linear,
unsteady state displacement tests carried out on core samples. The IMPES model uses either
linear interpolation or parameterization for the relative permeability and capillary pressure input
data (Li et al., 2014). The simulation is carried out on a block centered grid, i.e. pressures and
saturations calculated at the center of the block, with all blocks having the same length. Single
point upstream weighting of relative permeability is utilized (Heaviside, Black & J.F. Berry,
1983).
Even though the idea of relative permeability is hypothetically independent of experimental
parameters, laboratory data has previously suggested a dependence on variables, for example,
flow rate, and center length.
When a drainage case is considered, drainage displacement on the core scale is controlled by the
balance between viscous and capillary forces. Capillary pressure can manifest itself in two ways,
firstly by causing sample scale artefacts (end effects) and secondly by influencing the nature of
the displacement on the pore scale (dispersion of the flood front).
Provided suitable capillary pressure data is available, the numerical simulation method can be
used in a history matching mode to generate relative permeability curves from low rate
displacement tests. However, the general form of the relative permeability curves has to be
assumed.
However, for imbibition systems, the usefulness of simulation is limited. Empirical observations
are not consistent with the predictions from theory. Therefore, solutions are regarded as
approximate and it is recommended that laboratory measurements are conducted under
conditions as close as possible to the reservoir situation
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References
Hou, J., Wang, D., Luo, F., & Zhang, Y. (2012). A Review on the Numerical Inversion Methods of Relative
Permeability Curves. Procedia Engineering, 29, 375-380.
http://dx.doi.org/10.1016/j.proeng.2011.12.726
Honarpour, M., & Mahmood, S. (2015). Relative-Permeability Measurements: An Overview. Journal Of
Petroleum Technology, 40(08), 963-966. http://dx.doi.org/10.2118/18565-pa
Ediriweera, M., & Halvorsen, B. (2015). Study of the Effect of Relative Permeability and Residual oil
Saturation on Oil Recovery. Proceedings Name. http://dx.doi.org/10.3384/ecp15119339
Heaviside, J., Black, C., & Berry, J. (1983). Fundamentals of Relative Permeability: Experimental and
Theoretical Considerations. Society Of Petroleum Engineers Of AIME.
5. Measurement of Relative Permeability | Global CCS Institute. (2018). Hub.globalccsinstitute.com.
Retrieved 5 March 2018, from https://hub.globalccsinstitute.com/publications/relative-
permeability-analysis-describe-multi-phase-flow-co2-storage-reservoirs/5-measurement-
relative-permeability
Li, F., Yang, S., Chen, H., Zhang, X., Yin, D., He, L., & Wang, Z. (2014). An improved method
to study CO2–oil relative permeability under miscible conditions. Journal Of Petroleum
Exploration And Production Technology, 5(1), 45-53. http://dx.doi.org/10.1007/s13202-
014-0122-1
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