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Relationship between CCA (Conventional Core Analysis) and SCAL (Special Core Analysis)

Date:  2021-05-31 06:05:37
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Core analysis can be regarded as laboratory measurement physical and chemical properties of the samples recovered from the core. The analysis is used by multiple disciplines, for instance, the reservoir engineers need the reading from core analysis for complete interpretation of fluid flow properties. The reservoir engineers then used the analysis to design and optimize the recovery process (Sedlar & Barbir, 2016). It is admitted that establishment of proper methods of hydrocarbon reservoirs in positively dependent on the properties of porosity, permeability, and rock-fluid interactions.

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Core Analysis Preparation

After the proper preservation of the core, it is transferred to the laboratory where is analyzed for several properties. The analysis is divided into two main types known as:

1. Conventional Core Analysis (CCA).

2. Special Core Analysis (SCAL).

The properties to be analyzed include grain density, porosity, permeability, fluid saturation, electrical resistivity, and pressure. To perform this measurement, several steps should be taken in advance.

Conventional Core Analysis

Conventional Core Analysis (CCA) is done on every foot of the preserved core. The precaution to be taken while performing such analysis is the placement of plugs. It too many plugs fail in the regions where the base quality is not okay it might affect the result of analysis. To avoid such situations, the plugs are placed at least one foot far from each other. Also, the readings of plugs from two different lithologies should be prevented to reduce biasing from the readings (Barbir, 2016). The plugs can be cut in both parallel and perpendicular directions to avoid the biasing in orientations.

Special Core Analysis (SCAL)

Unlike CCA the samples are not gathered at regular intervals in SCAL. Specific attention is given to the type of rock to be analyzed. The location and number of samples to be collected are entirely dependent on the kind of rock under consideration (Barbir, 2016). A core which appears to be homogenous to the naked eye may be extremely heterogeneous of its petrophysical characteristics. Use of non-destructive imaging like CT scan is highly recommended to perform such analysis. It is also recommended to take samples at least twice for the particular measurement (Barbir, 2016), (Al-Gharbi, Jing, & Kraaijveld, 2007).


The Conventional Core Analysis (Conventional Core Analysis) is responsible for the measurement of physical properties of the core while SCAL (Special Core Analysis) used to measure electrical and physical properties of the preserved core. To get reliable results both analysis should be performed with extreme care as they are dependent on each other. A mistake in CCA can lead to a disputed result for SCAL. CCA is used to measure the physical properties of the preserved core. Based on the reading achieved in CAA the SCAL is performed to measure the chemical and electrical properties of the conserved core.

Conventional Core Analysis (CCA) Special Core Analysis (SCAL)

Porosity and Grain Density Measurement.

Bulk Volume.

Grain Volume (Needed for electrical measurements in SCAL).

Pore Volume.

Grain Density.

Permeability Measurement (Provides basis for measurement in SCAL). Electrical Properties dependent on pore volume calculated in CCA. Generally water is the common conductor in most of the analysis.

Resistivity Index of the Core.

Water Saturation (Chemical property dependent on the grain density measure in CCA).

Stability Measurement.

Permeability Measurement (Use of state of art technologies to check the readings obtained in CCA).

Table 1: Relationship between CCA and SCAL.

Factors Affecting Wettability and Capillary Pressure


Most of the petroleum reservoirs consist of three main components water, oil, and gas. While dealing with multiple systems, it is crucial to determine wettability properties of each of the fluids. It is defined as, The capability of a liquid to spread on a solid surface in the presence of other fluids (Derahman & Zahoor, 2008). For an oil related system, the wettability is the preference of the rock for oil and water. Changes in the wettability can have significant impacts on the results of core analysis performed on them. An ideal scenario is the placement of the highly preserved native-state cores should be selected to perform multi-flow experiments. These cores can minimize the changes in the wettability of the rocks (Zahoor, 2008). These tests include the measurers of salinity, SwI layer index, and diagnoses. On the other hand, if single-phase experiments like porosity and permeability are to be performed than cleaned cores can be used for calculations. While cleaning the cores, some extra care is allocated to clear the core of fluids by injecting various solvents in the cores (Zahoor, 2008). The third type is resorted-core, in which the core is first cleaned, saturated with brined and finally injected with oil. The core is then let to be aged in its natural reservoir temperatures to restore it to its initial wettability.

Capillary Pressure

Capillary pressure impacts the reservoir in two different ways. The pressure is responsible for the initial distribution of the fluids in the reservoir. The fluid acts under capillary-gravitational force and governs the way oil and gas move through its core before meeting a barrier. The capillary pressure is regarded as, the differential pressure between two unmixed fluids (Zahoor, 2008). In the case of oil reservoir, it is considered as the difference between the oil phase and water phase.

In the above equation,

PC = Capillary Pressure.

PO = Pressure of oil.

PW = Pressure of water.

The capillary pressure is dependent on both rock and fluid properties, i.e., both CCA and SCAL properties. The tension between the two fluids, wettability, and pore size distribution are the crucial factor in determining the capillary pressure of the reservoir. It is an important factor which can be used to determine the field-wide water saturation taking into account the height of reservoir.

Relative Permeability

This term is defined as, if the system is saturated with more than one liquid, the phenomenon of permeability requires to be extended to accommodate each liquid passing through its pores (Mosavat, Torabi, & Zarivnyy, 2013). The permeability of a fluid is required as it develops the relationship between saturation and conductivity of the liquid. Darcys equation is used to relate absolute permeability with relative one:

In the above equation, k = absolute permeability while kr = relative permeability.

The absolute permeability of the reservoir is totally a reservoir rock property. The relative permeability is dependent on the factors like wettability, the geometry of pores, interfacial tension, saturation, salinity, and history of congestion. As the measurement of relative permeability is influenced by several factors, it is not an easy task.

SW = Saturation of water.

SO = Saturation of oil.

An accurate measurement of relative permeability is of extreme importance for all reservoir engineering applications. While designing an oil recovery project, and estimating the water flood, it is necessary to input the correct values of the relationship between relative permeability and saturation into the simulating model (Zarivnyy, 2013). Conducting experiments in a reservoir environment are complicated, and it is advised to use native-state or restored cores to perform these tests.


Al-Gharbi, M. S., Jing, X., & Kraaijveld, M. (2007). SCAL Relative Permeability Measurements and Analyses for a Cluster of Fields in South Oman. International Petroleum Technology Conference. doi:10.2523/11415-ms

Karasalihovic-Sedlar, D., & Barbir, G. (2016). TYPES OF FI SCAL REGIME IN HYDROCARBON EXPLORATION AND PRODUCTION. Rudarsko-geolosko-naftni zbornik, 32(1), 45-53. doi:10.17794/rgn.2017.1.6

Mosavat, N., Torabi, F., & Zarivnyy, O. (2013). Developing New Corey-Based Water/Oil Relative Permeability Correlations for Heavy Oil Systems. SPE Heavy Oil Conference-Canada. doi:10.2118/165445-ms

Nawi Derahman, M., & Zahoor, M. (2008). Prediction and Estimation of Capillary Pressure for Wettability and Wettability Variations Within Reservoir. Proceedings of Abu Dhabi International Petroleum Exhibition and Conference. doi:10.2118/117799-ms

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