Petrophysical Properties Of Carbonate Rocks Research Articles

Comparative analysis of the application of the Lichtenecker and Lichtenecker – Asaad models for the theoretical assessment of the rocks effective thermal conductivity

The analysis of the conditions and limitations of using the Lichtenecker and Lichtenecker – Asaad models for predictive assessment of the effective thermal conductivity of rocks have been carried out. For a comparative assessment, experimental data on the thermal conductivity of carbonate rocks (limestone, dolomite) from the South-West German Molasse basin, the Chicxulub impact structure (Yucatan Peninsula, Mexico) and the Bazhenov Formation (Western Siberia, Russia) have been considered. Comparative assessments were carried out based on the use of correlation relationships obtained by the authors of experimental works as a result of regression analysis of the petrophysical properties of carbonate rocks. The results of the computational and analytical assessment have shown that the highest accuracy of thermal conductivity prediction using the Lichtenecker – Asaad model can be achieved if experimental data are available that provide a highly accurate determination of the structure factor. The features of the influence of various parameters of the Lichtenecker – Asaad model on the error in estimating the effective thermal conductivity of the rock have been studied. It has been established that at the stage of pre-design research, the Lichtenecker model can be used for a fairly correct theoretical assessment of the thermal conductivity of water-saturated, slightly porous rocks.

The Role of Clay Minerals in the Petrophysical Properties of Carbonate Rocks from the Cotinguiba Formation (Sergipe-Alagoas Basin, Brazil)

The Cotinguiba Formation, of Cretaceous age, located in the Sergipe-Alagoas Basin, Brazilian Northeastern coast, comprises carbonate breccias and carbonate shales interlayered with fine to coarse clastic sediments (mudstones, marls), deposited in the maximum sea level episode during the Cenomanian-Coniacian transgressive event. Core sections were selected from the formation materials, from which 20 plugs were obtained, representing the main carbonate horizons present in Cotinguiba Formation. The selected samples were analyzed with petrophysical and physical methods (air porosimetry, mercury injection, and acoustic wave velocity) and mineralogical methods (optical microscopic analysis, x-ray diffraction (XRD) and scanning electron microscopy (SEM)). Results showed that the clay minerals’ content in the carbonates varies from 2% to 20%, with illites/micas and interstratified illite/smectite as the most abundant clay minerals, containing also traces of chlorite and kaolinite, and presence of palygorskite varying from trace to 8%. According to the percentages of calcite, dolomite, and siliciclastic + clay minerals obtained in the XRD analysis, the carbonates were lithologically identified as limestone, impure limestone, dolomitic limestone, impure dolomitic limestone, impure calcitic dolostone, and impure dolostone. The rocks have a good porosity, varying from 6% to 20% in the carbonates, predominantly related to microporosity. Clay minerals’ content influenced the grain density and acoustic properties, albeit not having the same role with porosity and permeability. SEM images, though, show that they have an important role in microporosity. Grain density variation related to phyllosilicate content was observed more significantly in impure limestones with a clay content higher than 8%, and a more pronounced decrease was observed in samples with palygorskite. Microporosity is the main factor for reducing Vp and Vs velocities in those carbonates, with values not exceeding 5341 m/s for Vp and 3026 m/s for Vs but, when clay content is higher than 4%, the Vp and Vs wave velocities do not exceed 4100 m/s and 2480 m/s, respectively. Therefore, the research allowed evaluating the influence of mineralogical and textural properties in the petrophysical properties of Cotinguiba Formation.

Hydrothermal silicification and hypogene dissolution of an exhumed Neoproterozoic carbonate sequence in Brazil: Insights from fluid inclusion microthermometry and silicon‐oxygen isotopes

AbstractHypogene dissolution‐precipitation processes strongly affect the petrophysical properties of carbonate rocks and fluid migration pathways in sedimentary basins. In many deep carbonate reservoirs, hypogene cavernous voids are often associated with silicified horizons. The diagenesis of silica in carbonate sequences is still a poorly‐investigated research topic. Studies exploring the complexity of silica dissolution‐precipitation patterns in hypogene cave analogues are therefore fundamental to unravel the diagenetic and speleogenetic processes that may affect this kind of reservoir. In this work, we investigated an exhumed and silicified Neoproterozoic carbonate sequence in Brazil hosting a 1.4 km‐long cave. Quartz mineralization and silicified textures were analyzed with a multidisciplinary approach combining petrography, fluid inclusion microthermometry, silicon‐oxygen stable isotope analyses and U‐Th‐Pb dating of monazite crystals. We found that an early silicification event caused the replacement of the dolostone layers with micro‐crystalline quartz forming chert nodules. This event was likely associated with mixing fluids (ancient Neoproterozoic seawater and hydrothermal solutions sourced from the underlying Mesoproterozoic basement) at relatively low temperatures (ca. 50–100°C) and shallow depth. After the tectonic deformation produced by the Brasiliano orogeny, silica dissolution was promoted by high temperature and alkaline hydrothermal solutions rising from the quartzite basement along deep‐rooted structures. Hypogene hydrothermal alteration promoted the dissolution of the cherty layers and the precipitation of chalcedony and megaquartz. Homogenization temperatures from primary fluid inclusions in megaquartz cement indicate minimum formation temperatures of 165–210°C. Similar temperature estimates (110–200°C) were obtained from the δ30Si and δ18O isotope systematics of quartz precipitated from hydrothermal solutions. The dissolved salts in the fluid inclusions were evaluated as NaCl + CaCl2 from microthermometric data combined with cryogenic Raman spectroscopy, corresponding to salinity ranging between 17 and 25 wt.%. No reliable age constraints for hydrothermal silica dissolution‐precipitation phases were obtained from monazite U‐Th‐Pb dating. However, our results, interpreted in the regional context of the São Francisco Craton, suggest that the Cambrian tectono‐thermal events could have been amongst the possible drivers for this hypogene process in the basin.

Quantitative diagenesis: Methods for studying the evolution of the physical properties of tight carbonate reservoir rocks

Conventionally, diagenesis has been studied by making qualitative morphological observations which have been organised into complex classification schemes. Petrophysics, with its many quantitative measurements, now gives us the ability to quantify the effects of the type, degree and timing of complex diagenetic process. The aim of this paper is to examine how different diagenetic processes affect the petrophysical properties of carbonate rocks and to develop quantitative methodologies to describe the results of diagenetic processes. A large number of petrophysical measurements have been made on a suite of 172 core plugs to provide a test data set. Diagenetic modification of the primary depositional fabric was observed in a wide range of measured petrophysical parameters, and that porosity and pore connectedness exert dominant control on all of the electrical and hydraulic rock parameters. This observation has been used to propose a new theoretical framework linking the effect of diagenetic process to petrophysical measureables. Cementation exponent was found to increase with permeability and pore size, especially in recrystallized rocks, and is explained by smaller porosity samples having a better connected pore network. Electrical connectedness was also found to correlate extremely well with hydraulic permeability, showing that these phenomena are linked closely in tight carbonate reservoir rocks. A method for calculating pre- and post-dolomitisation porosity and the degree of dolomitisation from the measured petrophysical and compositional data has also been developed and tested. All electrical and hydraulic properties are related to pore type, allowing cementation exponent to be obtained from optical microscopy/SEM studies or NMR measurements, providing a new approach to estimating cementation exponent in carbonate rocks. This paper also provides a powerful new approach allowing petrophysical changes associated with the type, degree and timing of different diagenetic processes to be tracked quantitatively using a method we have called ‘petrodiagenetic pathways’.

Bioturbation enhanced petrophysical properties in the Ordovician carbonate reservoir of the Tahe oilfield, Tarim Basin, NW China

Bioturbation plays an important role in enhancing the reservoir capacity of tight reservoirs. This study aims to understand the alteration mechanism and effects of bioturbation on oil and gas reservoirs, to clarify the key control factors and constraints influencing the production of bioturbation. The petrophysical characteristics of bioturbation and host sediments in carbonate rocks, such as mineral composition, pore spaces, porosity and permeability, were studied based on the detailed observation and description of the Ordovician cores from the Tahe oilfield. The effect of bioturbation on petrophysical properties of carbonate rocks were carefully analyzed. The results show: (1) Two types of bioturbation, Thalassinoides-like burrows and Planolites-like burrows, mainly occur in the Ordovician cores of the Tahe oilfield, ranging from the Lower–Middle Ordovician Yingshan Formation to the Middle Ordovician Yijianfang Formation. The burrow-fills are mainly composed of dolomite with subhedral and euhedral crystals. The host sediments mainly consist of micrite. (2) The pores in the host sediments are poorly developed and are incapable of forming effective reservoir spaces. However, well-developed intercrystalline pores among dolomites and microfractures in bioturbated sediments with better connectivity can form effective pore spaces. The results of porosity and permeability show that the host sediments without bioturbation are characterized by poor porosity and permeability. However, with the increase of bioturbation intensity, the porosity of the bioturbated sediments firstly increases and then decreases, whereas the permeability increases all the time. (3) Multiple burrows overprinted in the Ordovician carbonate rocks, forming a large-scale bioturbated carbonate rocks with lateral continuity and vertical connectivity, due to the suitable sedimentary setting, ecological conditions, favorable spatiotemporal sediment matching, and abundant organism–substrate interaction. Subsequently, diagenesis (particularly dolomitization and dissolution) has played a positive role in altering the rock fabric and improving the petrophysical properties of bioturbated carbonates.

An integrated analysis of mineralogical and microstructural characteristics and petrophysical properties of carbonate rocks in the lower Indus Basin, Pakistan

Abstract Carbonate rocks are believed to be proven hydrocarbon reservoirs and are found in various basins of Pakistan including Lower Indus Basin. The carbonate rock intervals of the Jakkher Group from Paleocene to Oligocene age are distributed in south-western part of Lower Indus Basin of Pakistan. However, there are limited published petrophysical data sets on these carbonate rocks and are essential for field development and risk reduction. To fill this knowledge gap, this study is mainly established to collect the comprehensive high quality data sets on petrophysical properties of carbonate rocks along with their mineralogy and microstructure. Additionally, the study assesses the impact of diagenesis on quality of the unconventional tight carbonate resources. Experimental techniques include Scanning Electronic Microscopy (SEM), Energy-Dispersive X-ray Spectroscopy (EDS), and X-ray diffraction (XRD), photomicrography, Helium porosity and steady state gas permeability. Results revealed that the porosity was in range of 2.12 to 8.5% with an average value of 4.5% and the permeability was ranging from 0.013 to 5.8mD. Thin section study, SEM-EDS, and XRD analyses revealed that the samples mostly contain carbon (C), calcium (Ca), and magnesium (Mg) as dominant elemental components.The main carbonate components observed were calcite, dolomite, micrite, Ferron mud, bioclasts and intermixes of clay minerals and cementing materials. The analysis shows that: 1) the permeability and porosity cross plot, the permeability and slippage factor values cross plots appears to be scattered, which showed weaker correlation that was the reflection of carbonate rock heterogeneity. 2) The permeability and clay mineralogy cross plots have resulted in poor correlation in these carbonate samples. 3) Several diagenetic processes had influenced the quality of carbonates of Jakkher Group, such as pore dissolution, calcification, cementation, and compaction. 4) Reservoir quality was mainly affected by inter-mixing of clay, cementation, presence of micrite muds, grain compactions, and overburden stresses that all lead these carbonate reservoirs to ultra-tight reservoirs and are considered to be of very poor quality. 5) SEM and thin section observations shows incidence of micro-fractures and pore dissolution tended to improve reservoir quality.

Pore-scale modeling of carbonates

Abstract Carbonate rocks display complex pore textures with heterogeneities that extend over several length scales. Identifying and capturing the significant pore space properties in a computationally tractable model is therefore nontrivial. Pore-scale models bridge predictions of transport properties from sub-pore to core scale and attempts have been made to render such methods cost-effective. This chapter reviews several methods for fabricating pore-scale models of carbonate rocks and discusses approaches to simulating their fluid flow and solute transport properties. The advantages and limitations of each method in reducing the reservoir development uncertainties are explained. We argue that pore-scale models can play an important role in predicting the petrophysical properties of carbonate rocks. Even more importantly, they provide sensitivity analyses of pore-scale features on macroscopic transport observations and offer explanations for anomalous flow behaviors.

The seismic signature of heavy oil on carbonate reservoir through laboratory experiments and AVA modelling

Abstract The influence of unconventional oil on the petrophysical properties of carbonate rocks is of primary interest in petroleum science. In this work, we first provided a thorough petrophysical characterization in laboratory by measuring density, porosity, VP and VS of a bitumen carbonate reservoir rock outcropping in the Majella Mountain (Central Italy). The presence of bitumen stiffens the rock and causes an increases of the acoustic impedance (AI) and a strong decrease of the VP/VS ratio respect to brine saturation. On the contrary, lighter oil causes a decrease of the AI and a slight decrease of the VP/VS ratio in comparison with a saturation in brine. Then, we performed a Synthetic Amplitude vs Angles (AVA) modelling showing that through the AVA analysis, it is possible to recognize the type of fluid that saturates the analyzed carbonate reservoir rocks. We also observed that the increasing porosity plays a key role in the AVA response, by decreasing the bulk density and seismic waves velocities and increasing the amount of fluids that saturate the rocks. By applying our laboratory and modelling results to a public stacked seismic line we show that our results may help in recognize heavy oil directly from seismic data.

Combined interpretation of NMR, MICP, and SIP measurements on mud-dominated and grain-dominated carbonate rocks

Carbonate formations still present a challenging target with regard to reservoir characterization as they possess a wide range of pore types and sizes as well as interconnected and isolated pore space. In this study a set of micritic and oomoldic carbonate samples was investigated with three measurement techniques (magnetic resonance (NMR), mercury intrusion (MICP), and spectral induced polarization (SIP, in a frequency range from 5mHz to 100 Hz)) which provide information about a rock's pore space indirectly based on different physical principles. The aims of the study were to combine these pieces of information to characterize the pore space of mud-dominated and grain-dominated carbonate rocks and to investigate potential correlations between pore space properties and SIP-derived parameters.Pore body and pore throat size distributions were derived from NMR and MICP data, respectively, and interpreted in terms of dominant pore throat (rt) radius, pore body (rb) radius and the rb/rt ratio. For validation of the NMR-derivedrb distributions, scanning electron microscope images were used for the computation of image-derived pore size distributions. The SIP data were interpreted in terms of characteristic features for oomoldic and micritic samples. Phase shift, real (σ′) and imaginary part (σ′′) of complex conductivity, respectively, were fitted with Cole-Cole models and the characteristic parameters relaxation time τ, chargeability m, and frequency dependence c were derived for each sample. Subsequently, these parameters were interpreted with regard to correlations with rb,rt, and rb/rt and specific surface Spor.The results indicate that grain-dominated carbonates possess comparatively large radii rb and rtand low Spor, which seems to go along with sharp phase peaks (i.e. high c values) and a low absolute phase level (and therefore low chargeability m). The mud-dominated carbonates, in contrast, possess relatively small radii rb and rt and high Spor which is obviously associated with broad phase peaks (i.e. low c values) and a comparatively high phase level resulting in high m values. τ, in contrast, was found to decrease with increasing ratio rb/rt and may therefore have similar values in both micritic and oomoldic samples. Consequently, the results of this study contribute to a better understanding of the petrophysical properties of carbonate rocks as a function of their pore space characteristics.

Impact of Diagenetic Alterations on the Petrophysical and Multiphase Flow Properties of Carbonate Rocks Using a Reactive Pore Network Modeling Approach

Sedimentary reservoir rocks generally have complex and heterogeneous pore networks that are related to the original depositional rock texture and subsequent diagenetic alterations. Such alterations are in part controlled by the original mineralogy and sedimentological facies, the compaction history, the involved fluids (and rock/fluid interactions), the flow history and the related physico-chemical conditions. During the diagenetic evolution (paragenesis), cycles of alternating dissolution (porosity enhancement) and precipitation (porosity destruction) caused by changes in chemical and thermodynamic conditions may lead to heterogeneous rock structure at both local and reservoir scale.In the absence of cored plugs to measure the petrophysical properties (i.e. porosity, permeability and formation factor) and multiphase flow properties (i.e. capillary pressure, relative permeability and resistivity index), a numerical tool that calculates these properties from pore structure data by predicting its evolution during the diagenetic cycle is of great interest for the petroleum industry and reservoir characterization studies.A Pore Network Model (PNM) provides opportunities to study transport phenomena in fundamental ways because detailed information is available at the pore scale. It has been used over the last decades to understand basic phenomena such as capillarity, multiphase flow or coupled phenomena. In particular, this modeling approach is appropriate to study the rock/fluid interactions since the mass exchange at surfaces can be modeled explicitly. It can provide quantitative information both on the effective transport property modifications due to the reactions and on the structure evolution resulting from dissolution/precipitation mechanisms. In the present paper, this approach is used to study the effect of the diagenetic cycle on the petrophysical properties of carbonate rocks. It involves three discrete steps. The first step consists of replacing the original complex pore structure of real porous media by a conceptual network. The second step consists of resolving the governing equations of the precipitation and dissolution phenomena (i.e. reactive convection diffusion equation) in the conceptual 3D pore network and deducing the local reactive fluxes and the motion of the fluid-solid interface. The third step consists of updating the new pore structure and calculating the new petrophysical properties of the modified porous media. Those steps are repeated in order to mimic a given diagenetic scenario. Finally, the multiphase flow properties of the current porous media are calculated.The impact of one diagenetic cycle of dissolution and precipitation on the pore networks’ heterogeneity and consequently on the petrophysical properties (i.e. porosity and permeability) and multiphase flow properties (i.e. relative permeability and capillary pressure) have been investigated. The permeability and porosity evolution during a given diagenetic cycle are calculated and analyzed as a function of the relevant dimensionless numbers (Peclet and Damkohler numbers) that characterize the flow and reaction regime. The correlation between these numbers and the dissolved/precipitated layer thickness distribution is investigated.This work contributes to improve the understanding of the impact of dissolution and precipitation on permeability and porosity modification. Using the PNM approach, multiphase flow properties and permeability-porosity relationship have been determined for different reactive flow regimes. These relationships are relevant input data to improve the quality of reservoir simulation predictions.

An integrated study of the petrophysical properties of carbonate rocks from the “Oolithe Blanche” formation in the Paris Basin

Petrophysical properties were measured on oolitic limestone from the Oolithe Blanche formation (middle Jurassic) in the Paris Basin. Eighteen oriented blocks were collected from three outcrops regarding of the three main facies, oolitic shoal facies, tide dominated facies and prograding oolitic facies. We investigated the relationship between both compressional wave and electrical conductivity with different petrophysical properties such as porosity (water porosity and mercury porosity), permeability and capillarity imbibition. These have led us to relate the variations of petrophysical properties to several microstructural parameters, among them the microporous structure is the most important. Concerning P wave velocities, the general trend observed is as expected a decrease of velocities as the porosity increases but with a significant fluctuation of velocities for a given value of porosity. We have used two distinct effective medium approximations to describe the velocity variations: the self-consistent (SC) approximation and the cemented contact theory (CCT) but no unique model can simply explain our velocity behaviours. The main parameter that controls the P wave velocities is the distribution of microporosity inside oolites: for samples with velocities higher than 4 km/s the microporosity is mainly located in the rim of the ooids while for samples with velocity lower than 4 km/s the microporosity is homogeneous across the ooids. Acoustical fabrics, which are controlled by the facies, indicate that sedimentary textural components such as the amount of cement and arrangement of elements within the oolitic limestones (bioclasts, pellets and ooids) and their degree of connectivity may have some influences on the acoustic velocities. In contrast with acoustic properties, the electrical conductivity data are not so clustered by facies indicating that transport properties are more influenced by microstructural heterogeneities. One single Archie's law can well account for all the data sets but these sets also show a large range of tortuosity factor related to the microporosity arrangement inside oolites. Some good predictive permeability modeling were found using mercury injection spectra. Our investigations reveal that, the best way for fluids to flow is to pass through the microporosity in the oolites, and that permeability depends mainly of the connectivity of the ooids, which is certainly related to the facies.

INFLUENCES OF ASPHALTENE PRECIPITATION ON CAPILLARY PRESSURE AND PORE SIZE DISTRIBUTION OF CARBONATE RESERVOIRS

Asphaltene depositio n has profound effects on oil flow through porous medium. The investigation of the influences of asphaltene precipitation on carbonate reservoir rocks has minor interests in comparison to studies investigated sandstones ones. Therefore, this study is undertaken to provide accurate insights, especially for carbonate reservoirs of low permeability. In this study, two groups of experiments are undertaken. The first experimental group investigates effects of asphaltene precipitation on (a) petrophysical properties of carbonate rocks, including absolute permeability, effective porosity, and hydraulic radius, and (b) on oil-water relative permeability and water flooding performance. The second group searches for the effects of asphaltene precipitation on capillary pressure and pore size distribution of low permeability carbonate reservoirs. Conducted experiments are achieved using actual reservoir liquids of crude oil and brine, flowing through actual carbonate cores under similar reservoir conditions of temperature and pressure. The results indicated that asphaltene precipitation damages absolute permeability and hydraulic radius drastically, reduces effective porosity, and improves relative permeability of water for different asphaltene contents of crude oil flowing through carbonate reservoirs. In addition, oil reservoirs of high asphaltene content have shown higher values of irreducible water saturation than that ones of low asphaltene content in their crude oils. Precipitation of asphaltene in carbonate rock causes changes in the position of capillary pressure at high mobile oil saturation and reduces values resulted for pore size distribution curves, especially for small pore radii carrying crude's of high asphaltene content. Neglecting the proven influences of asphaltene precipitation may lead to erroneous description of carbonate reservoirs. Therefore, analysis of petrophysical properties and pore size distribution of carbonate reservoirs has to be updated during the extended life of oil reservoir and based upon accurate values of asphaltene content of the flowing crude oils. Applications of the attained results of this study are expected to provide real improvement in reservoir description, more reliable estimation of oil reserves, accurate predicted values of reservoir rock damage, and also better descriptive functions for future reservoir simulation studies.