Determining the capillary pressure behavior of rocks at reservoir temperature and pressure is vital in understanding the displacement mechanism in the reservoir. An understanding of the displacement mechanism is essential to evaluate its effect on fluid saturations and oil recovery. The evaluation of saturations and thus oil reserves from resistivity logs requires laboratory determination of both the cementation factor (m) and the saturation exponent (n) under conditions as representative as possible of reservoir ones. Special laboratory equipment using air and actual formation brine at reservoir temperature and under effective overburden pressure was developed. The porous plate method was used to determine capillary pressure curves and saturation exponent at ambient conditions and at full reservoir conditions, (reservoir pressure and temperature) on sandstone core plugs from a Libyan reservoir. The main objective of this study was to determine whether any difference exists between the capillary and electrical properties obtained at ambient conditions and those obtained at reservoir conditions for rock samples. Prior to the test, the effect of overburden pressure on porosity and formation factor can be studied.

Porosity, water saturation, and net-to-gross evaluation can be challenging in thinly bedded sands. The use of standard induction resistivity for formation evaluation can lead to the overestimation of water saturation. This work explores the following options to improve formation evaluation in these conditions: the use of high resolution density and nuclear magnetic resonance (NMR) data to improve porosity vertical resolution; the use of high-resolution resistivity from an oil-based-mud microresistivity imaging tool in improving the saturation computation ( S w ); and the comparison of imaging tool resistivity-based sand count and NMR-based thin-bed fraction. Using high-resolution porosity inputs from density and NMR provided a porosity curve with a better vertical resolution to match the high resolution resistivity from the imaging tool. It also identified additional productive thin beds compared to the standard resolution outputs and allowed computation of a high-resolution irreducible water saturation. The induction-based Sw is strongly affected by shoulder bed effect and overestimates S w by approximately 10 to 15%. The high-resolution curve from the imaging tool was used as an input into the S w computation, which was made possible by shallow oil-based mud (OBM) invasion. This approach gave good results in beds thicker than 6 in., where S w from the imaging tool matches the irreducible water saturation computed from NMR, giving 20 to 30% S w . A thin-bed fraction curve was computed from the NMR data. It shows a good match with the image-based high resolution- sand count and the image features, demonstrating that NMR and the imaging tool are equally able to identify and quantify thin beds, even though they have different vertical resolutions. This study showed that the microresistivity imaging tool and NMR are essential tools to characterize thinly bedded reservoirs.

The permeability prediction is of extreme importance in hydrocarbon reservoir management. The reservoir rocks are made up of grains, cement and pore network. The pore network is made up of larger spaces, referred to as pores, which are connected by small spaces referred to as throats. The pore spaces control the amount of porosity, while the pore throats control the movement of fluids and the quantity of rock permeability. The core analysis data for 219 sandstone and limestone samples were available. The data include porosity, permeability and capillary pressure by mercury injection. These samples represent 21 stratigraphic units. The geologic age varied between Cretaceous and Pliocene. Sandstone reservoirs are represented by 179 samples, while 40 samples represent carbonate reservoirs. The data were collected from different geographic areas within Egypt. Pore-throat size distribution parameters were calculated from the data of capillary pressure. These data were used to approximate the distribution of pore volume accessible by throat of a given effective size. A new definition for micro-porosity was proposed based on pore throat size distribution. These data was used to descriminate the sample porosity into micro and macro porosity based on a pore throat cutoff, which was determined from the relationship between storage and flow capacity of the pore network. The relationship between permeability and aspects of pore geometry; micro-porosity, macro-porosity and pore throat parameters have been analyzed and discussed. The interpretation of the results indicates that the permeability is mainly a function of pore-throat size distribution while the amount of the porosity or the porosity configuration is not the main factor that controls the amount of permeability. A new model for permeability prediction was develpoed which incorporate the pore space and pore throat. The obtained results have shown the great influence of pore throat on permeability prediction.

Belayim Land field is one of the oldest and largest oil fields in Egypt. It produces oil from many sandstone reservoirs. Oil is produced from 4-30 ohm-m resistivity in Belayim Formation, while to the contrary, in Rudeis Formation, 70–80 ohm-m resistivity is producing water. Rock characterization program was planned for Rudeis Formation using core material. It includes porosity, permeability, thin section description, SEM, wettability, relative permeability and capillary pressure by mercury injection to obtain pore throat size distribution. The wettability of the reservoir rock was determined by Amott method and proved to be strongly oil wet. The wettability controls the position of fluids within the pore network, where in oil-wet the water saturation distributed as poorly connected droplets within the macro-pores and filled the micro-pores. To simulate the saturation history of the reservoir, restored-state samples at irreducible water saturation were flooded with water to perform electrical resistivity measurements. Non-linear curves were obtained during the electrical resistivity measurements. Two saturation exponents (n) values were proposed to reflect the mechanism of forming continuous water film from the water droplets. The inflection point between the two (n) values was used to determine the resistivity cutoff below which water is produced. In addition, it represents the water saturation cutoff which was confirmed from the calculation of fractional flow of water from relative permeability measurements. The production data confirm the use of variable (n) to monitor the water saturation in oil-wet reservoirs.