Cementation exponent

The pore system is described by the volume fraction of pore space (the fractional porosity) and the shape of the pore space which is represented by m , known as the cementation exponent. The cementation exponent describes the complexity of the pore system i.e. how difficult it is for an electric current to find a path through the reservoir. 

Fluid saturation, which defi nes oil-water contact, was determined using wireline log interpretation and RFT data. Shaliness was obtained through density/neutron log data and the salinity of the formation water was analysed from RFT sampled water. Additional parameters used in the calculation, such as saturation and cementation exponents (n and m, respectively), and tortuosity coefficient (a), were measured in the laboratory. 

The ratio of the resistivity (R ) in sediment to the resistivity (R. ) in pore water defines the formation (resistivity) factor (F). (a) and (m) are constants which characterize the sediment composition. As Archie (1942) assumed that (m) indicates the consolidation of the sediment it is also called cementation exponent (cf. Sect. 3.2.2). Several authors derived different values for (a) and (m). For an overview please refer to Schon (1996). In marine sediments often Boyce s (1968) values (a = 1.3, m = 1.45), determined by studies on diatomaceous, silty to sandy arctic sediments, are applied. Nevertheless, these values can only be rough estimates. For absolutely correct porosities both constants must be calibrated by an additional porosity measurement, either on discrete samples or by gamma ray attenuation. Such calibrations are strictly only valid for that specific data set but, with little loss of accuracy, can be transferred to regional environments with similar sediment compositions. Wet bulk densities can then be calculated using equation 2.3 and assuming a grain density (cf. also section 3.2.2). 

Fig. 2.7 Formation factor versus porosity for six gravity cores retrieved from different sedimentation provinces in the South Atlantic. Porosities were determined on discrete samples by wet and dry weights and volumes, formation factors by resistivity measurements. The dashed lines indicate Archie s law for a = 1 and cementation exponents (m) between 1 and 5. For a description of the sedimentation provinces, core numbers, coring locations, sediment compositions, water depths and constants (a) and (m) derived from linear least square fits please refer to Table 2.1. Unpublished data from M. Richter, University Bremen, Germany.

Table 2.1 Geographical coordinates, water depth, core length, region and composition of the sediment cores considered in Figure 2.7. The cementation exponent (m) and the constant (a) are derived from the slope and intercept of a linear least square fit to the log-log display of formation factors versus porosities.

Core Coordinates Water Depth Core Length Region Sediment Composition Factor (a) Cementation Exponent (m)... 

Qv expresses the clay effect m. is Archie s cementation exponent in the order of approximately 2. 

Grid-based reservoir core properties total porosity, absolute permeability, formatitHi resistivity factor and corresponding cementation exponent m, elastic moduli assuming isotropy (bulk modulus k, shear modulus p. Young s modulus E, Poisson s ratio o, and Lame s parameter X), and corresponding acoustic velocities. 

Archie noted that the exponent has a value of about 1.3 for unconsolidated sands and a range between 1.8 and 2.0 for many consolidated sandstones. Therefore, m was called the cementation exponent . 

FIGURE 8.14 Archie s exponent for rocks with separate-vug porosity (a) Correlation between cementation exponent and vug porosity ratio points are experimental data the line is the regression (Eq. 8.23). (b) Alternative calculation using Eq. (8.25) for totai = 0.1, 0.2, and 0.3 (curve parameter), compared with the experimental data Panel (a) After Lucia (2007). 

Focke, J.W., Munn, D., 1987. Cementation exponents in Middle Eastern carbonate reservoirs. SPE Form. Eval. 2, 155-167. June. Paper SPE 13735. 

Rasmus, J.C., 1983. A variable cementation exponent, m, for fractured carbonates. Log Anal. 

Accelerated solvent extraction (ASE), capillary chromatography sample preparation, 4 609, 610 Accelerated temperature, humidity, and bias (THB) tests, 10 9 Accelerated weathering tests, 19 584 Acceleration, exponents of dimensions in absolute, gravitational, and engineering systems, <5 584t Accelerators, 9 554-555 10 411, 713 22 61 23 861-862 for cement, 5 485... 

This paper reports an investigation of the effects of porous solid structures on their electrical behaviour at different frequencies (from 100 Hz to 100 kHz). For that, we study different parameters such as formation resistivity factor, cementation factor, chargeability, resistivity index and saturation exponent. Different porous solid structures are quantified from the petrographic image analysis and Hg-injection technique. Then, by using different models we obtain the permeability prediction from the electrical behaviour and structure parameters. 

Samples used in this study, their formation, petrographic, petrophysical and mineralogical characteristics. C crystal carbonate M-W mudstone, wackestone P-G packstone-grainstone Vac vugs iX intercrystalline pores iM intramatrix pores iG intragranular pores IG intergranular pores K karsts Fr fractures F formation factor m cementation factor n saturation exponent. 

F formation factor, m cementation factor n saturation exponent water porosity water permrability (mD) ... 

More than thirteen carbonate samples are studied to measure classic electric parameters in saturated and unsaturated geological carbonate porous systems. The values of the cementation factor m range finm 1.55 to 2.49. The dolomitic crystal texture shows the highest value. The electrical behaviour of the carbonate porous system in a unsaturated medium is studied from the saturation exponent n. The highest values of n are obtained for a dolomite crystal carbonate (n = 3.5) while the lowest values of n are obtained for a mudstone-wackestone texture (n = 1.2). The values of the chargeability factor M range between 0.19 and 0.5, and they depend on the brine/gas saturation of the carbonate porous system, carbonate textures and the salinity of brine in a porous medium. 

Figure 9.14 shows as example the calculated thermal conductivity versus porosity for a different exponent a. The variation of a fills the space between maximum and minimum curve. Also, for this mixing equation the comparison with experimental data is given. The exponent is controlled by the cementation for the sandstone results a=0.0-0.5, and for the marine clay aw-1.0-0.5. 

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