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Digital SCAL from 3D Rock Images

Capillary Pressure & Two-Phase Flow Analysis

Digital Special Core Analysis (SCAL) with GeoDict delivers a faster, non-destructive, and reproducible alternative and supplement to traditional lab-based methods. By simulating two-phase flow and fluid distribution – such as oil and water – directly on micro-CT or other 3D images of porous reservoir rocks, GeoDict enables accurate prediction of capillary pressure curves, relative permeability, and hysteresis behavior. These insights are critical for reservoir characterization, production forecasting, and enhanced oil recovery planning.

With ready-to-use workflows and no need for physical core alteration, digital SCAL reduces turnaround time from months to days, while preserving sample integrity.

It also allows engineers to test multiple saturation scenarios, boundary conditions, and rock types. Moreso, grasping the flow and pore connectivity unlocks previously unattainable insights to understand and visualize the pore-scale fluid dynamics.

Oil displaces water in a water-saturated Berea sandstone. The saturation of the oil phase increases with increasing capillary pressure.

For operators, service providers, and core labs looking to enhance decision-making and reduce operational risk, digital SCAL is a high-impact tool for reservoir evaluation, whether validating experimental SCAL or bridging data gaps in complex formations.

Authors and application specialists

Dr. Christian Hinz

Head of Oil & Gas Business

Lobel Danicic

Account Manager Oil & Gas

Dr. Arne Jacob

Application Engineer
for Digital Rock Physics

Part 1: Realistic Simulation of Hysteresis and Rock Aging - with GeoDict

Every DRP workflow starts with segmentation of rock images and generation of rock model. With the 3D microstructure in place, GeoDict enables simulation of the entire capillary pressure hysteresis cycle – capturing every key stage of two-phase flow.

The workflow allows to simulate

  • Primary Drainage: oil displacing water,
  • Imbibition (spontaneous+forced): water spontaneously re-entering the structure, and water flooding,
  • Secondary Drainage: spontaneous oil re-entering, forced oil re-displacing water

With each pressure step, saturation and fluid distribution in the rock are recorded in detail.

Grossmont carbonate, with pore and calcite
Fig. 1 Grossmont carbonate, with pore and calcite

A crucial advantage: GeoDict takes wetting properties at the mineral level into account – for realistic oil-wet, water-wet, or mixed-wet scenarios. Rock aging after primary drainage can also be simulated to realistically capture changing wetting conditions.

Grossmont carbonate with partially aged mineral surfaces
Fig. 2 Grossmont carbonate with partially aged mineral surfaces

Thanks to predefined workflows and an intuitive user interface, these complex simulations can be performed without programming – quickly, transparently, and reproducibly.

Part 2: Effective Automation of the Workflow

Extensive automation of the individual workflows is possible in GeoDict. In this case study, the complete hysteresis cycle was simulated using the Hysteresis for Oil-Water Setups GeoApp already included in GeoDict. The simulation scenarios and input parameters used for the simulation may be freely modified according to the application requirements.

When implemented in GeoDict, the entire contact angle range (water-wet, neutrally-wet, oil-wet, mixed-wet) of the simulated fluids is mapped according to the individual wetting properties of the rock. GeoDict is also used to simulate both porous plate and centrifugal standard experiments in the calculation of the properties of two-phase flow in porous media.

In the intuitive GUI, the user has access to the following input parameters:

  • Fluid properties
  • Wetting conditions
  • Contact angle
  • Interfacial tensions
  • Flow direction
Visualization of a partially oil-saturated structure of a Berea sandstone during primary drainage
Fig. 3 Visualization of a partially oil-saturated structure of a Berea sandstone during primary drainage
Visualization of flow velocities based on the calculation of the relative permeability of a Berea sandstone
Fig. 4 Visualization of flow velocities based on the calculation of the relative permeability of a Berea sandstone

This enables the automation of demanding digital SCAL scenarios with full control and technical precision.

The following modules were used

PoroDict MatDict FlowDict SatuDict

Part 3: Calculation of the Relative Permeability of Large Structures

Large rock structures can be evaluated quickly and cost-effectively with GeoDict’s digital simulation capabilities. GeoDict offers alternative to extensive laboratory testing by simulating capillary pressure curves and deriving relative permeability curves directly from high-resolution 3D rock models – saving both time and resources.

At each pressure step, the saturation distribution of the fluid phases is calculated in detail. Based on selected saturation levels, the effective permeability of each phase is computed, allowing accurate prediction of relative permeability as a function of saturation. Throughout the workflow, users maintain full control over simulation parameters, ensuring transparency, reproducibility, and traceability of results.

Case study: Gildehauser sandstone³

The whole hysteresis cycle was simulated, starting with primary drainage, and following with spontaneous and forced imbibition under consideration of partial aging of mineral surfaces after the primary drainage process. The accompanying relative permeabilities of water and oil phase have been computed.

GeoDict provides industry standards such as the Corey and LET models, which allow discrete simulation results to be parameterized as continuous functions. This facilitates integration into reservoir simulators and history matching workflows – and closes the gap between pore physics and field scale. The result: more informed decisions in reservoir development.

Simulation parameters

Mineral surface contact angles:

  • Initial CA: 40°
  • CA of aged mineral surfaces: 140°

Results of the capillary pressure curve calculation:

  • Irreducible Water saturation: 15 %
  • Residual Oil saturation: 42 %

Used computational resources:

  • Duration: ~20 hours
  • RAM: ~95 GB
  • Parallelization: 32 Cores
  • Software: GeoDict 2025
[Translate to English:] Digitale Gildehauser-Sandsteinprobe (4,4 µm, 900 x 900 x 566), die in dieser Fallstudie verwendet wurde.
Fig.5 Digital Gildehauser sandstone sample (4.4 µm, 900x900x566) used in this case study.
Capillary pressure curve of the complete hysteresis cycle
Fig. 6 Capillary pressure curve of the complete hysteresis cycle
Relative permeability during imbibition
Fig. 7 Relative permeability during imbibition

Visualization of flow velocities in the relative permeability simulation

References / Relevant publications

Burmester, G., Zekiri, F., Jurcic, H., Arnold, P., Ott., H., Integration and Upscaling of Multi-Phase Fluid Flow Properties in Clastic Reservoirs, 83rd EAGE Annual Conference & Exhibition, Conference Proceedings, pages 1-5, 2022 https://doi.org/10.3997/2214-4609.202210939

Arnold, P., Dragovits, M., Linden, S., Hinz, C., & Ott, H. (2023). Forced imbibition and uncertainty modeling using the morphological method. Advances in Water Resources, 172, 104381. https://doi.org/10.1016/j.advwatres.2023.104381

Berg, S., Rücker, M., Ott, H., Georgiadis, A., Van der Linde, H., Enzmann, F., Kersten, M., Armstrong, R., De With, S., Becker, J., & Wiegmann, A. (2016). Connected pathway relative permeability from pore-scale imaging of imbibition. Advances in Water Resources, 90, 24-35. https://doi.org/10.1016/j.advwatres.2016.01.010

Andrä, H., Combaret, N., Dvorkin, J., Glatt, E., Han, J., Kabel, M., Keehm, Y., Krzikalla, F., Lee, M., Madonna, C., Marsh, M., Mukerji, T., Saenger, E. H., Sain, R., Saxena, N., Ricker, S., Wiegmann, A., & Zhan, X. (2012). Digital rock physics benchmarks—Part I: Imaging and segmentation. Computers & Geosciences, 50, 25-32. https://doi.org/10.1016/j.cageo.2012.09.005

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