Moustafa Dernaika | University of Stavanger (original) (raw)
Papers by Moustafa Dernaika
OBJECTIVES/SCOPE: Shales are heterogeneous source rocks and often exhibit complex pore systems. E... more OBJECTIVES/SCOPE: Shales are heterogeneous source rocks and often exhibit complex pore systems. Economical hydrocarbon production from shales necessitates a detailed understanding of the complex reservoir characteristics. This paper presents key characteristics from several unconventional formations in the Middle East including porosity, permeability, organic matter (OM) and Brittleness Index, and their dependence on mineralogy, clay content and pore type. METHODS PROCEDURES, PROCESS: More than one-thousand data sets from 14 wells and three different formations in the Middle East were analyzed in this study. The analyses started with full-diameter whole cores that were initially evaluated using dual energy X-ray CT scanning to locate potentially high-quality rock intervals with high porosity and high OM. Two-dimensional Scanning Electron Microscopy (2D SEM) and three-dimensional Focused Ion Beam (3D FIB-SEM) analyses were studied to characterize the kerogen content and porosity together with (organic and inorganic) porosity, grain size and rock fabric. The mineral framework of the samples was determined from X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and Energy Dispersive Spectral (EDS) analyses. Matrix permeability was directly computed in the 3D FIB-SEM images using the Lattice Boltzmann Method. Brittleness Index (BI) was calculated from mineralogy. Trend analyses of the collected data were performed for proper shale evaluation and comparisons. RESULTS, OBSERVATIONS, CONCLUSIONS: Large property variations were seen in the evaluated formations, and each reservoir showed unique characteristics and different controlling parameters. Mineralogy, clay content and organic matter content were three main controlling factors that had direct effects on the porosity. Organic matter and pore type were also critical parameters in 3D connectivity and determination of permeability. In a single mineralogy system, a strong relation was observed between brittleness index and organic matter. Novel/Additive Information: The data studied provided statistical information about the dependence of shale properties on many different factors in different formations. These data trends can be linked to the varying depositional environments that were found to have a great effect on the pore types, rock fabric and petrophysical properties. Such analysis is a critical addition to the understanding of shales in the Middle East, and may be used in direct comparisons with shale plays in North America.
Reliable experimental capillary pressure and electrical properties as functions of saturation his... more Reliable experimental capillary pressure and electrical properties as functions of saturation history are essential as inputs for static and dynamic modeling of a reservoir. The only technique that simultaneously gives both capillary pressure and resistivity index as functions of saturation history, and does not rely on a model with underlying assumptions for calculation, is the porous-plate desaturation method. The main disadvantage with this method is that it is time consuming, caused by the low ux through the porous plate or membrane. We present drainage capillary pressure curves and resistivity index measured on reservoir rock samples by the porous-plate method at pseudo reservoir conditions. In parallel with this, another plug set has been analyzed by interrupting intermediate capillary displacement pressures before reaching equilibrium, with the objective of establishing S w-RI relationship much faster. The results show that it is possible to establish identical S w-RI relationship with a time-saving factor of three for the carbonate rock type under study. The saturation data were tted to an exponential-decay model using nonlinear regression in order to derive accurate capillary pressure curves from short-wait porous-plate measurements. A similar model was suggested to describe the resistivity index change and was found to occur at a faster rate than the water saturation change.
Most carbonate reservoirs are commonly characterized by multiple-porosity systems that impart pet... more Most carbonate reservoirs are commonly characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross of reservoir interval. This heterogeneity complicates the task of reservoir description and thus necessitates the establishment of accurate and detailed understanding of the geological heterogeneities and their impact on petrophysics and reservoir engineering.
Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoi... more Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale is a wide variety of rocks that are composed of extremely fine-grained particles with very small porosity and permeability values in the order of few porosity units and nano-darcy range, respectively. Shale formations are very complex at the core scale, and exhibit large vertical variations in lithology and Total Organic Carbon (TOC) at a small scale that renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale pore level where the pores have different porosity types that are detected within the kerogen volume. These complexities led to further research and development of advanced application of high resolution X-ray CT scanning on full diameter core sections to characterize shale mineralogy, porosity and rock facies so that accurate evaluation of the sweet spot locations could be made for further detailed petrophysical and petrographic studies. In this work, argillaceous shale gas cores were imaged using high resolution dual energy X-ray CT scanning. This imaging technique produces continuous whole core scans at 0.5mm spacing and derives accurate bulk density and effective atomic number (Z eff) logs along the core intervals which were crucial in determining lithology, porosity, and rock facies. Additionally, integrated XRD data and energy dispersive spectrum (EDS) analysis were acquired to confirm the mineral framework composition of the core. Smaller core plugs and subsamples representing the main variations in the core were extracted for much higher resolution X-ray CT scanning and Scanning Electron Microscopy (SEM) analysis. Porosity was mainly found in organic matter and was determined from 2D and 3D SEM images by image segmentation process. Horizontal fluid flow was only possible through the organic matter and the simulations of 3D FIB-SEM volumes by solving Stokes equation using Lattice Boltzmann Method (LBM). A clear trend was observed between porosity and permeability while correlating with identified facies in the core. Silica-rich facies gave higher Phie-K characteristics compared to the low clay-rich facies. This is mainly caused by pressure compaction effect in the soft clay-rich samples. High percentages of organic matter were not found to be good indication for high porosity or permeability in the clay-rich shale samples. The depositional facies was found to have great effect on the pore types, rock fabric and reservoir properties. The results and interpretations entailed in this study provide further insights and enhance our understanding of heterogeneity of the organic rich shale reservoir rock.
Carbonate rocks are complex in their structures and pore geometries and often exhibit a real prob... more Carbonate rocks are complex in their structures and pore geometries and often exhibit a real problem in their classification and behavior. Many petrophysical and fluid flow properties remain unexplained and perhaps uncertain because of improper characterization of the reservoir rock. In this research, carbonate rock types were defined from thin-sections based on the structure of the rock together with its pore types. The rock type classifications were improved by incorporating pore-throat size distribution and poro-perm information, and high resolution plug CT images. This would lead to a robust rock typing scheme that should facilitate the understanding of heterogeneity effects on reservoir flow properties. Laboratory-measured imbibition relative permeability (Kr) data were determined on reservoir core samples in two " mixed-wet " carbonate fields from the Middle East region. The Kr curves were explained based on the identified rock types and gave consistent trends. The Kr curves were fitted with Corey exponents, and yielded high " no " and low " nw " for the higher permeability samples, which may be wrongly interpreted as more oil-wet rocks compared to the lower permeability samples. The variations in Kr curves with the different rock types were argued to be the result of different rock structures and pore geometries that control pore accessibility and surface area. The obtained Krw and Kro data from steady state experiments are not abundant in the literature and hence should serve as an important piece of information in mixed-wet carbonate reservoirs with varying rock types.
Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable c... more Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011). This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements. The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well's core. Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements.
SPE Reservoir Characterisation and Simulation Conference and Exhibition, 2015
The evaluation of carbonate reservoirs is a complex task because of the inherent heterogeneities ... more The evaluation of carbonate reservoirs is a complex task because of the inherent heterogeneities that occur at all length scales. Rock properties may be defined differently at different scales and this introduces a challenge in capturing heterogeneity in a single rock volume. Heterogeneities at smaller length scales must be upscaled into larger scale volumes to better predict reservoir performance. The objective in this study is to define carbonate rock types at multiple scales and then upscale those rock types and associated properties to the whole core level.
The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained s... more The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including total organic carbon (TOC) content, mineralogy, maturity and grain-size. The ultra-low permeability of the shale rock requires massive hydraulic fracturing to enhance connectivity and increase permeability for the flow. To design an effective fracturing technique, it is necessary to have a good understanding of the reservoir characteristics and fluid flow properties at multiple scales. In this work, representative core plug samples from a tight carbonate source rock in the Middle East were characterized at the core-and pore-scale levels using a Digital Rock Physics (DRP) workflow. The tight nature of the carbonate rocks prevented the use of conventional methods in measuring special core analysis (SCAL) data. Two-dimensional Scanning Electron Microscopy (SEM) and three-dimensional Focused Ion Beam (FIB)-SEM analysis were studied to characterize the organic matter content in the samples together with (organic and inorganic) porosity and matrix permeability. The FIB-SEM images in 3D were also used to determine petrophysical and fluid flow (SCAL) properties in primary drainage and imbibition modes. A clear trend was observed between porosity and permeability related to identified rock fabrics and organic matter in the core. The organic matter was found to have an effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The data obtained from DRP provided information that can enhance the understanding of the pore systems and fluid flow properties in tight formations, which cannot be derived accurately using conventional methods. Introduction Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale comprises a variety of rocks that are composed of extremely fine-grained particles with very low porosity and permeability values in the order of few porosity units and nano-darcy range, respectively. Shale formations are very complex at the core scale, and exhibit large vertical variations in lithology and Total Organic Carbon (TOC) at a small scale that renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale where the pores have different porosity types that are detected within kerogen and rock matrix.
SPE Middle East Unconventional Resources Conference and Exhibition, 2015
PETROPHYSICS, VOL. 55, NO. 1, Feb 1, 2014
A detailed laboratory study to determine capillarity and resistivity in reservoir rocks for a hug... more A detailed laboratory study to determine capillarity and resistivity in reservoir rocks for a huge carbonate eld in Abu Dhabi using porous-plate measurements at reservoir temperature and reservoir overburden pressure conditions has been completed. Representative reservoir core samples were selected based on whole-core and plug X-ray CT, NMR T 2 , high-pressure mercury-injection, porosity, permeability and thin-section analyses. The results of primary drainage (PD), spontaneous imbibition (SI), and forced imbibition (FI) experiments are presented in this work, which captures the capillary -pressure behavior and the electrical-resistivity changes all the way to irreducible brine saturation for drainage, and residual oil saturation for imbibition.
This paper presents work on laboratory advances that have been developed to measure capillary pre... more This paper presents work on laboratory advances that have been developed to measure capillary pressure and electrical property measurements under low water saturation conditions. The paper discusses in some detail the various capillary pressure techniques utilized in the oil and gas industry and gives some insights on the Kelvin equation's applicability in tight gas sands. Detailed comparisons are shown between vapor desorption capillary pressure and mercury injection data a saturation offset that could be attributed to the non-wetting nature of the fluids and possible rock matrix alteration. The proposed calibration of the mercury data on tight sands is then considered for tight gas carbonate reservoirs.
Characterization of carbonate reservoirs is challenging as well as daunting due to the inherent h... more Characterization of carbonate reservoirs is challenging as well as daunting due to the inherent heterogeneities that occur at all scales of observation and measurement. Heterogeneity in carbonates can be attributed to variable lithology, chemistry/mineralogy, pore types, pore connectivity, and sedimentary facies. These complexities can be related to processes controlling original deposition and their subsequent diagenesis.
Experimental measurements of capillary pressure, resistivity index and relative permeability disp... more Experimental measurements of capillary pressure, resistivity index and relative permeability display hysteresis manifested through the dependence of these properties on the saturation path and saturation history whenever fluid saturations undergo cyclic processes. At the pore scale, hysteresis is typically influenced by contact-angle hysteresis, trapping of one phase by another and wettability changes.
In this research work, a graph theoretical approach has been introduced to find a mathematical mo... more In this research work, a graph theoretical approach has been introduced to find a mathematical model for the change of hardness of weakly cross-linked polymer network systems with the change of configurations. The polymers studied are (i) poly(methyl methacrylate), (ii) styrene -acrylonitrile copolymer and (iii) polystyrene. In very weakly cross-linked polymer network systems, both the chain entanglement and the network rigidity competitively contribute to the hardness of polymer network. The average length (i.e. molecular weight), and length distribution of chains between the cross-linking sites both play important roles in network rigidity. The former can be changed by the mole fraction of the cross-linker, and the latter by the molecular weight of the prepolymer formed, which can be controlled by the late addition of the cross-linker. Graph theoretical approach introduces simplifications to the dynamics of polymer chains and polymer network, and thus can explain the change of hardness with the change of chain statistics. It was shown that there was a very good agreement between the theoretical equations and the experimental hardness values of polymer network systems studied. It was also found that there were scaling relations between the parameters used in the theoretical equation.
Relative permeability curves generally exhibit hysteresis between different saturation cycles. Th... more Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.
OBJECTIVES/SCOPE: Shales are heterogeneous source rocks and often exhibit complex pore systems. E... more OBJECTIVES/SCOPE: Shales are heterogeneous source rocks and often exhibit complex pore systems. Economical hydrocarbon production from shales necessitates a detailed understanding of the complex reservoir characteristics. This paper presents key characteristics from several unconventional formations in the Middle East including porosity, permeability, organic matter (OM) and Brittleness Index, and their dependence on mineralogy, clay content and pore type. METHODS PROCEDURES, PROCESS: More than one-thousand data sets from 14 wells and three different formations in the Middle East were analyzed in this study. The analyses started with full-diameter whole cores that were initially evaluated using dual energy X-ray CT scanning to locate potentially high-quality rock intervals with high porosity and high OM. Two-dimensional Scanning Electron Microscopy (2D SEM) and three-dimensional Focused Ion Beam (3D FIB-SEM) analyses were studied to characterize the kerogen content and porosity together with (organic and inorganic) porosity, grain size and rock fabric. The mineral framework of the samples was determined from X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and Energy Dispersive Spectral (EDS) analyses. Matrix permeability was directly computed in the 3D FIB-SEM images using the Lattice Boltzmann Method. Brittleness Index (BI) was calculated from mineralogy. Trend analyses of the collected data were performed for proper shale evaluation and comparisons. RESULTS, OBSERVATIONS, CONCLUSIONS: Large property variations were seen in the evaluated formations, and each reservoir showed unique characteristics and different controlling parameters. Mineralogy, clay content and organic matter content were three main controlling factors that had direct effects on the porosity. Organic matter and pore type were also critical parameters in 3D connectivity and determination of permeability. In a single mineralogy system, a strong relation was observed between brittleness index and organic matter. Novel/Additive Information: The data studied provided statistical information about the dependence of shale properties on many different factors in different formations. These data trends can be linked to the varying depositional environments that were found to have a great effect on the pore types, rock fabric and petrophysical properties. Such analysis is a critical addition to the understanding of shales in the Middle East, and may be used in direct comparisons with shale plays in North America.
Reliable experimental capillary pressure and electrical properties as functions of saturation his... more Reliable experimental capillary pressure and electrical properties as functions of saturation history are essential as inputs for static and dynamic modeling of a reservoir. The only technique that simultaneously gives both capillary pressure and resistivity index as functions of saturation history, and does not rely on a model with underlying assumptions for calculation, is the porous-plate desaturation method. The main disadvantage with this method is that it is time consuming, caused by the low ux through the porous plate or membrane. We present drainage capillary pressure curves and resistivity index measured on reservoir rock samples by the porous-plate method at pseudo reservoir conditions. In parallel with this, another plug set has been analyzed by interrupting intermediate capillary displacement pressures before reaching equilibrium, with the objective of establishing S w-RI relationship much faster. The results show that it is possible to establish identical S w-RI relationship with a time-saving factor of three for the carbonate rock type under study. The saturation data were tted to an exponential-decay model using nonlinear regression in order to derive accurate capillary pressure curves from short-wait porous-plate measurements. A similar model was suggested to describe the resistivity index change and was found to occur at a faster rate than the water saturation change.
Most carbonate reservoirs are commonly characterized by multiple-porosity systems that impart pet... more Most carbonate reservoirs are commonly characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross of reservoir interval. This heterogeneity complicates the task of reservoir description and thus necessitates the establishment of accurate and detailed understanding of the geological heterogeneities and their impact on petrophysics and reservoir engineering.
Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoi... more Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale is a wide variety of rocks that are composed of extremely fine-grained particles with very small porosity and permeability values in the order of few porosity units and nano-darcy range, respectively. Shale formations are very complex at the core scale, and exhibit large vertical variations in lithology and Total Organic Carbon (TOC) at a small scale that renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale pore level where the pores have different porosity types that are detected within the kerogen volume. These complexities led to further research and development of advanced application of high resolution X-ray CT scanning on full diameter core sections to characterize shale mineralogy, porosity and rock facies so that accurate evaluation of the sweet spot locations could be made for further detailed petrophysical and petrographic studies. In this work, argillaceous shale gas cores were imaged using high resolution dual energy X-ray CT scanning. This imaging technique produces continuous whole core scans at 0.5mm spacing and derives accurate bulk density and effective atomic number (Z eff) logs along the core intervals which were crucial in determining lithology, porosity, and rock facies. Additionally, integrated XRD data and energy dispersive spectrum (EDS) analysis were acquired to confirm the mineral framework composition of the core. Smaller core plugs and subsamples representing the main variations in the core were extracted for much higher resolution X-ray CT scanning and Scanning Electron Microscopy (SEM) analysis. Porosity was mainly found in organic matter and was determined from 2D and 3D SEM images by image segmentation process. Horizontal fluid flow was only possible through the organic matter and the simulations of 3D FIB-SEM volumes by solving Stokes equation using Lattice Boltzmann Method (LBM). A clear trend was observed between porosity and permeability while correlating with identified facies in the core. Silica-rich facies gave higher Phie-K characteristics compared to the low clay-rich facies. This is mainly caused by pressure compaction effect in the soft clay-rich samples. High percentages of organic matter were not found to be good indication for high porosity or permeability in the clay-rich shale samples. The depositional facies was found to have great effect on the pore types, rock fabric and reservoir properties. The results and interpretations entailed in this study provide further insights and enhance our understanding of heterogeneity of the organic rich shale reservoir rock.
Carbonate rocks are complex in their structures and pore geometries and often exhibit a real prob... more Carbonate rocks are complex in their structures and pore geometries and often exhibit a real problem in their classification and behavior. Many petrophysical and fluid flow properties remain unexplained and perhaps uncertain because of improper characterization of the reservoir rock. In this research, carbonate rock types were defined from thin-sections based on the structure of the rock together with its pore types. The rock type classifications were improved by incorporating pore-throat size distribution and poro-perm information, and high resolution plug CT images. This would lead to a robust rock typing scheme that should facilitate the understanding of heterogeneity effects on reservoir flow properties. Laboratory-measured imbibition relative permeability (Kr) data were determined on reservoir core samples in two " mixed-wet " carbonate fields from the Middle East region. The Kr curves were explained based on the identified rock types and gave consistent trends. The Kr curves were fitted with Corey exponents, and yielded high " no " and low " nw " for the higher permeability samples, which may be wrongly interpreted as more oil-wet rocks compared to the lower permeability samples. The variations in Kr curves with the different rock types were argued to be the result of different rock structures and pore geometries that control pore accessibility and surface area. The obtained Krw and Kro data from steady state experiments are not abundant in the literature and hence should serve as an important piece of information in mixed-wet carbonate reservoirs with varying rock types.
Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable c... more Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011). This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements. The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well's core. Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements.
SPE Reservoir Characterisation and Simulation Conference and Exhibition, 2015
The evaluation of carbonate reservoirs is a complex task because of the inherent heterogeneities ... more The evaluation of carbonate reservoirs is a complex task because of the inherent heterogeneities that occur at all length scales. Rock properties may be defined differently at different scales and this introduces a challenge in capturing heterogeneity in a single rock volume. Heterogeneities at smaller length scales must be upscaled into larger scale volumes to better predict reservoir performance. The objective in this study is to define carbonate rock types at multiple scales and then upscale those rock types and associated properties to the whole core level.
The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained s... more The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including total organic carbon (TOC) content, mineralogy, maturity and grain-size. The ultra-low permeability of the shale rock requires massive hydraulic fracturing to enhance connectivity and increase permeability for the flow. To design an effective fracturing technique, it is necessary to have a good understanding of the reservoir characteristics and fluid flow properties at multiple scales. In this work, representative core plug samples from a tight carbonate source rock in the Middle East were characterized at the core-and pore-scale levels using a Digital Rock Physics (DRP) workflow. The tight nature of the carbonate rocks prevented the use of conventional methods in measuring special core analysis (SCAL) data. Two-dimensional Scanning Electron Microscopy (SEM) and three-dimensional Focused Ion Beam (FIB)-SEM analysis were studied to characterize the organic matter content in the samples together with (organic and inorganic) porosity and matrix permeability. The FIB-SEM images in 3D were also used to determine petrophysical and fluid flow (SCAL) properties in primary drainage and imbibition modes. A clear trend was observed between porosity and permeability related to identified rock fabrics and organic matter in the core. The organic matter was found to have an effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The data obtained from DRP provided information that can enhance the understanding of the pore systems and fluid flow properties in tight formations, which cannot be derived accurately using conventional methods. Introduction Unconventional shale reservoirs differ largely from conventional sandstone and carbonate reservoirs in their origin, geologic evolution and current occurrence. Shale comprises a variety of rocks that are composed of extremely fine-grained particles with very low porosity and permeability values in the order of few porosity units and nano-darcy range, respectively. Shale formations are very complex at the core scale, and exhibit large vertical variations in lithology and Total Organic Carbon (TOC) at a small scale that renders core characterization and sweet spot detection very challenging. Shale formations are also very complex at the nano-scale where the pores have different porosity types that are detected within kerogen and rock matrix.
SPE Middle East Unconventional Resources Conference and Exhibition, 2015
PETROPHYSICS, VOL. 55, NO. 1, Feb 1, 2014
A detailed laboratory study to determine capillarity and resistivity in reservoir rocks for a hug... more A detailed laboratory study to determine capillarity and resistivity in reservoir rocks for a huge carbonate eld in Abu Dhabi using porous-plate measurements at reservoir temperature and reservoir overburden pressure conditions has been completed. Representative reservoir core samples were selected based on whole-core and plug X-ray CT, NMR T 2 , high-pressure mercury-injection, porosity, permeability and thin-section analyses. The results of primary drainage (PD), spontaneous imbibition (SI), and forced imbibition (FI) experiments are presented in this work, which captures the capillary -pressure behavior and the electrical-resistivity changes all the way to irreducible brine saturation for drainage, and residual oil saturation for imbibition.
This paper presents work on laboratory advances that have been developed to measure capillary pre... more This paper presents work on laboratory advances that have been developed to measure capillary pressure and electrical property measurements under low water saturation conditions. The paper discusses in some detail the various capillary pressure techniques utilized in the oil and gas industry and gives some insights on the Kelvin equation's applicability in tight gas sands. Detailed comparisons are shown between vapor desorption capillary pressure and mercury injection data a saturation offset that could be attributed to the non-wetting nature of the fluids and possible rock matrix alteration. The proposed calibration of the mercury data on tight sands is then considered for tight gas carbonate reservoirs.
Characterization of carbonate reservoirs is challenging as well as daunting due to the inherent h... more Characterization of carbonate reservoirs is challenging as well as daunting due to the inherent heterogeneities that occur at all scales of observation and measurement. Heterogeneity in carbonates can be attributed to variable lithology, chemistry/mineralogy, pore types, pore connectivity, and sedimentary facies. These complexities can be related to processes controlling original deposition and their subsequent diagenesis.
Experimental measurements of capillary pressure, resistivity index and relative permeability disp... more Experimental measurements of capillary pressure, resistivity index and relative permeability display hysteresis manifested through the dependence of these properties on the saturation path and saturation history whenever fluid saturations undergo cyclic processes. At the pore scale, hysteresis is typically influenced by contact-angle hysteresis, trapping of one phase by another and wettability changes.
In this research work, a graph theoretical approach has been introduced to find a mathematical mo... more In this research work, a graph theoretical approach has been introduced to find a mathematical model for the change of hardness of weakly cross-linked polymer network systems with the change of configurations. The polymers studied are (i) poly(methyl methacrylate), (ii) styrene -acrylonitrile copolymer and (iii) polystyrene. In very weakly cross-linked polymer network systems, both the chain entanglement and the network rigidity competitively contribute to the hardness of polymer network. The average length (i.e. molecular weight), and length distribution of chains between the cross-linking sites both play important roles in network rigidity. The former can be changed by the mole fraction of the cross-linker, and the latter by the molecular weight of the prepolymer formed, which can be controlled by the late addition of the cross-linker. Graph theoretical approach introduces simplifications to the dynamics of polymer chains and polymer network, and thus can explain the change of hardness with the change of chain statistics. It was shown that there was a very good agreement between the theoretical equations and the experimental hardness values of polymer network systems studied. It was also found that there were scaling relations between the parameters used in the theoretical equation.
Relative permeability curves generally exhibit hysteresis between different saturation cycles. Th... more Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.