Petrophysical Values Research Articles

Experimental Study of Seismic Wave Attenuation in Carbonate Rocks

Summary Seismic wave attenuation has a great potential for studying saturated and fractured media, due to its high sensitivity to the physical properties of geological media. However, accurately estimating this parameter can be challenging due to its sensitivity to signal noise, particularly in heterogeneous media such as carbonate rocks. This explains the paucity of attenuation studies carried out in carbonate rocks compared with sandstones, and the ambiguity around its mechanisms and its relationship with petrophysical properties. To investigate further, we conducted an experimental study of ultrasonic waveform signals (0.5–3 MHz) reordered under dry and fully saturation conditions in 13 samples covering a wide range of petrophysical values and subjected them to differential pressure reaching reservoir pressure. The resulting increase in attenuation magnitudes and their variation with pressure due to brine saturation were more pronounced than in velocity magnitudes, confirming the higher sensitivity of attenuation to fluid content. However, understanding the relationship between attenuation and petrophysical properties required a careful examination of the results and more elucidation about attenuation mechanisms. We suggested that multiple attenuation mechanisms coexist, including scattering, cracks slipping, solid frictional relative motion, and global and squirt flow. This explains the frequency dependence of attenuation, with higher magnitudes at sonic frequencies, where the squirt flow mechanism may be dominant. In contrast to sandstone, the magnitude of compressional to shear attenuation ratio (QP−1/QS−1) was found to be greater than unity in both dry and brine fully saturated carbonate samples at ultrasonic frequencies. This result may be due to the complex porosity structure of carbonate rocks, which makes it not appropriate to the sandstone rock physics models.

Development of a hydrate risk assessment tool based on machine learning for CO2 storage in depleted gas reservoirs

Depleted gas reservoirs are attractive sites for Carbon Capture and Storage (CCS) due to their huge storage capacities, proven seal integrity, existing infrastructure and subsurface data availability. However, CO2 injection into depleted formations can potentially lead to hydrate formation near the wellbore due to Joule-Thomson cooling, which might cause injectivity issues. Some challenges encountered when modeling and simulating this process are the computational time caused by Newton’s convergence issues and instability. The objective of this work is to propose a novel approach for hydrate risk assessment during CO2 injection into depleted gas reservoirs using physics-based Machine Learning (ML) approach. First, the selection of input parameters for the ML models is performed based on sensitivity study results using an analytical solution for different operational and petrophysical values. Then the ML models are tuned and tested using datasets from numerical reservoir simulation results based on a wide range of input parameter values. To the best of our knowledge, this is the first time that an ML approach is used for risk assessment of CO2 hydrate in its storage in depleted gas reservoirs. The ML models developed in this study presented an efficient performance to predict hydrate-forming events. The deep neural network model performed best with a 95% recall value and 84% precision value. These results show that the ML model can be further utilized for risk assessment in the screening stage, and the combination of screening by ML, followed by detailed analysis with numerical simulation in high-risk cases can be an efficient probing workflow for future CCS projects.

Application of unsupervised learning and deep learning for rock type prediction and petrophysical characterization using multi-scale data

This study integrates well log data, routine core analyses, microcomputed X-ray tomography (μCT) images, and sedimentary petrography to accurately characterize and evaluate the carbonate reservoirs of the Barra Velha formation (Aptian) of the Santos Basin within Brazilian pre-salt region. In these carbonate reservoirs, the porous system is extremely diverse and variable, making it challenging to establish rock typing with comparable petrophysical properties. Based on this integrated study, the reservoir sequences were characterized and a precise definition of four reservoir rock types (RRTs) was performed by integrating the petrophysical values from the plugs and their corresponding well log data of two cored wells using K-means unsupervised classification algorithm. The classification results were combined with various conventional techniques to evaluate the quality and geological characteristics of the studied sequence. This evaluation encompassed different parameters such as flow and storage capacity, reservoir quality index, flow zone indicator, pore spaces interpretation, and average pore and throat radius. The study involved a detailed analysis of thin sections to identify various facies, including shrubstones, reworked, and spherulitestone, and to classify various forms of porosity such as interparticle, intraparticle, intercrystalline, vug, moldic, fracture, and growth framework porosity. Pore Network Modeling from μCT analysis of plugs was used specifically for the characterization of pores and throats of plug samples from each RRT. These datasets were utilized as supporting evidence to offer a more accurate and inclusive knowledge of reservoir quality. The study aimed to develop predictive models by implementing deep learning and machine learning algorithms trained on well log data to estimate plug porosity and rock type. Two deep learning models, ResNet and 1D CNN, were trained and evaluated for plug porosity prediction, with the 1D CNN model showing superior performance. Additionally, the XGBoost algorithm was applied to predict rock type, achieving high accuracy on both the training and validation datasets. The predicted results were compared with actual data to evaluate the effectiveness of the models and were then utilized to estimate plug permeability values. The results demonstrate the potential of deep learning and machine learning approaches in reservoir characterization and management, enabling the evaluation of subsurface reservoir properties even with incomplete datasets, which could lead to an improved understanding of the reservoir properties and better management of the reservoir. This integrated study provides deeper insight into the complex reservoir properties and can help improve decision-making processes and optimize management and production strategies in the challenging pre-salt carbonate reservoirs or similar complex reservoirs.

Petrophysical Calculation Analysis and Determination of Cut-Off in Betung Field, Jambi-Sub-Basin, South-Sumatera-Basin

Petrophysical properties provide a comprehensive approach to reservoir characterization, in which reservoir quality is of paramount importance. The main controllers for reservoir quality are porosity, permeability and clay content. Petrophysical models are used by utilizing the correlation between tool response (logging) and rock and fluid properties. These petrophysical results will be cut-off to distinguish productive and unproductive parts of a reservoir. Petrophysical and cut-off calculations in the Betung Field are applied to determine the quality and productive zone of the Air Benakat Formation reservoir. The direction of field development (infill wells) is based on the quality of the reservoir and productive zone obtained based on the results of petrophysical and cut-off calculations. This research was conducted in Layer 5 (L-5) of the Betung Field using the main data, namely well logs (Gamma ray, density, neutron, resistivity). Well logs were processed to obtain petrophysical values using Interactive Petrophysic and Microsoft Excel software. Petrophysical results were then cut-off on clay content, porosity and water saturation, so that a productive zone was obtained from the Betung L-5 field. Petrophysical and cut-off results show L-5 is a Hydrocarbon prospect zone with an average petrophysic value for well 210 (Vclay: 32%, porosity: 25% and water saturation: 65%); well 220 (Vclay: 35%, porosity: 30% and water saturation: 38%); well 222 (Vclay: 8.2%, porosity: 31% and water saturation: 28%). The resulting cut-off values for well 210 (Vclay: 42.6%, porosity: 17% and water saturation: 98%); well 220 (Vclay: 26.6%, porosity: 22.4% and water saturation: 50.3%); well 222 (Vclay: 18%, porosity: 17% and water saturation: 70.4%).

Geothermal reservoir characterisation of Devonian carbonates in North Rhine-Westphalia (W. Germany): Mineralogy- and depofacies-related extrapolation of petrophysical parameters

Across Germany, coal-fired power plants will be shut down not later than 2038. In the Rhine-Ruhr area of western Germany, their waste heat is the main supply for one of Europe’s largest district heating networks. Because of the projected shutdown of coal-fired power plants, sustainable alternatives must be implemented. This paper evaluates the hydrothermal potential of Devonian carbonates. A depofacies and mineralogy model is proposed and discussed. Tentative conclusions are drawn based on petrophysical laboratory tests. Extrapolating the thermal and hydraulic rock properties into geothermal reservoir depths offers constraints for associated reservoir simulations. This task applies existing and derived extrapolation equations taking local pressure and temperature gradients into consideration. The change from a non-linear to a linear development at the critical crack-closure pressure provides evidence regarding the petrophysical in-situ reservoir conditions. Results show a positive effect of increased dolomite volumes on reservoir properties. The spatial distribution of fracture networks significantly affects the geothermal reservoir potential, whereas the impact of regionally distributed depofacies variations is moderate. The critical crack-closure pressure equals 40MPa for limestones and 60MPa for dolomitic limestones, as well as dolostones, representing depths of approx. 3.6 and 5.4km, respectively. At depths of 6km, non-linear and linear extrapolation principles must be applied accordingly. At that depth, the thermal conductivity decreases by 14 to 20% compared to the outcrop values, depending on the sample category. The equivalent decrease in porosity amounts to one to two orders of magnitude. The permeability decrease equals three to four orders of magnitude. The petrophysical values of outcrop samples discussed here plot, within the error range, in the same domain as those of the Malm carbonates in the Munich area. Results are considered encouraging for those concerned with the sustainable transition of the district heating network in the Rhine-Ruhr area. Side-strands of regionally important fault systems, often characterised by hydrothermal dolomitisation, combine tectonic and petrophysical aspects that are advantageous and highly relevant for hydrothermal operations.

Determination of the Maxx Prospect Zone Petrophical Parameters in MA06 Well MA Field with Log Data Analysis

The well logging method is one of the methods used in petrophysical analysis to assess the formations used in obtaining information and shadows related to a reservoir. In addition, in an effort to determine success in the oil and gas field, this method is also included for calculating petrophysical values such as permeability, water saturation, and porosity. Then this value will be used in finding the initial oil reserves (OOIP) and initial gas reserves (GIIP) in the MA field. This will be very helpful in developing further oil and gas fields because materials are available as a basis for reference. This study analyzes the MA field precisely at the MA-06 Well by utilizing the qualitative and quantitative petrophysical analysis method by only referring to log data because there is no availability of core data. To find out the depth of the prospect zone and what fluid is in the formation, the authors analyze it in a qualitative way, namely by determining the permeable zone, then looking at the resistivity value, then determining the type of fluid on track 3. While in obtaining petrophysical values such as shale volume, porosity, water saturation and rock permeability the authors chose to use quantitative methods to analyze them. So that the results of the analysis carried out, it was found that the MAXX well has a net sand thickness of 36 feet and a net pay of 36 feet with an average value of shale volume, porosity, water saturation and permeability in that zone respectively 34.8%. , 18.03%, 35.3%, and 38.31 mD.

Assessment of the relationship of reservoir properties of hydrocarbon fields in the Lower Kura depression (Kursengi and Southern Kursengi areas)


 
 
 The article is devoted to the analysis of the geological-petrophysical properties of the Kursengi and Southern Kursengi fields of the Lower Kura depression with a view to clarify the changes in the physical properties (carbonate content, permeability, porosity) of rocks with depth. Promising sediments and horizons of deposits are also considered based on a detailed analysis of numerous rock samples. Oil and gas bearing objects are especially distinguished by area, as well as possible oil and gas bearing blocks. The main purpose of these studies is to unravel changes in carbonate, porosity and permeability of rocks with depth based on core samples taken from drilled wells in the study area and to identify the factors causing these changes. To do this, using the obtained well data, the dependences of changes in depth of porosity, permeability and carbonate were compiled. As known, with increasing depth, rocks experience compaction. With the depth of changes in porosity, the rocks do not show any regularity, i. e. at some depths, an increase in the porosity of rocks is observed, and at some depths, a decrease, and this occurs in an abrupt manner. In our sections, the critical depths of porosity decrease are observed from 500 m to 1600 m, and the critical depth of porosity increase from 1600 m to 2950 m. In other words, the porosity of reservoirs, with a general gradual decrease in depth, begins to sharply decrease from a depth of 3200 m. In the study of core materials, it was found that the rocks are characterized by good reservoir properties. However, in many of the studied samples, the porosity of the rocks varies within a wide range of 12.8–27.8 %, and the permeability ranges from 0.001x10–15m2 to 120x10–15m2. Changes in petrophysical values are observed in both study areas. The reason for the change in petrophysical values in a wide range at the objects of study is associated with the lithological heterogeneity of the complexes and the occurrence depth of the reservoir.
 
 

Focusing joint inversion of gravity and magnetic data using a clustering stabilizer in a space of weighted parameters

SUMMARY This paper develops a minimum-support focusing stabilizer to perform a joint inversion of the vertical components of gravity and magnetic data using fuzzy c-means clustering (FCM) with the regularized Newton method in a space of weighted parameters. Not only does this joint inversion technology arrive at the conditionally well-posed traditional potential field inversion, but it also increases the structural correlation between multiple inverted models. The FCM and the focusing stabilizer make it possible to balance the convergence of the data space (D) and the model space (M), guiding multimodal geophysical parameters toward assigned petrophysical values, which makes the results more stable and realistic. Two model studies are presented to illustrate the method, a simple synthetic model with two rectangular bodies in a homogenous background and a realistic model of the Volcanogenic Massive Sulfide (VMS) deposits in northeastern New Brunswick, Canada. These models demonstrate that the new focusing joint inversion algorithm produces better images than traditional methods because the FCM function uses the structural correlation of density contrast and magnetic susceptibility as constraints.

Characterizing scales of sedimentary heterogeneity in a fluvial—estuarine reservoir analog: An example from the Mulichinco Formation, Neuquén Basin, Argentina

An integrated stratigraphic, sedimentological and petrophysical analysis is presented to document the variety of sedimentary heterogeneities scales that can occur in a fluvial–estuarine reservoir analog. In this context, outcrops of the Mulichinco Formation (Neuquén Basin, Argentina) were investigated combining architectural analysis, vertical and lateral facies organization, and reservoir properties distributions in different channel-body types. Six main facies associations have been defined: gravelly–sandy to sandy braided channels, meandering channels, floodplain deposits, tidally influenced terminal channels, and subtidal to intertidal plains deposits, which we interpret the deposition in a proximal to distal fluvial and inner estuarine systems. Sequence stratigraphic analysis suggest the fluvial–estuarine succession evolved from a lower to an upper interval representative of low to high accommodation versus sediment supply ratios, respectively. Variations in accommodation and spatial changes from on-to off-axis locations within the fluvial system might performed as large-scale controls in stratigraphic and spatial variations of channel-deposits proportions and connectedness, which decreases vertically and horizontally towards the N and SE. Moreover, these trends could be overprinted by the avulsion influence. Distribution and preservation-style of fines within the channels define different intra-channel-body compartments controlled by distinct allogenic and autogenic processes. Cross-bedded sandstones represent the facies with the greatest reservoir quality, but they record the widest range in petrophysical values and textural variations, which represent unfavourable potential facies-scale reservoir compartments and barriers. Finally, variations in cement mineralogy would be the first-order control for permeability distribution and reservoir quality separation throughout the different channel units, since clay-rich cements contain the highest values of microporosity and permeability. Therefore, primary depositional processes followed by diagenesis strongly controlled the sandstone properties as reservoir. This work provides a characterization for stratigraphic-to pore-scale sedimentary heterogeneities and may contribute to the improvement of predictive models for exploration and development strategy of fluvial–inner estuarine reservoirs.

Integrated Work Flow Optimizes Eagle Ford Field Development

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195951, “Case Study: Optimizing Eagle Ford Field Development Through a Fully Integrated Work Flow,” by Adrian Morales, SPE, Robert Holman, and Drew Nugent, Chesapeake Energy, et al., prepared for the 2019 SPE Annual Technical Conference and Exhibition, Calgary, 30 September-2 October. The paper has not been peer reviewed. An integrated project can take many forms, depending on available data, from a simple horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations to a large-scale seismic-to-simulation work flow. The complete paper presents a large-scale work flow designed to take a vast amount of data into consideration. The work flow can be scaled for projects of any size, depending on the data available. Introduction In 2017, Chesapeake Energy launched an investigation to evaluate ways of improving overall recoveries within the lower Eagle Ford. Two theoretical approaches were generated to optimize the company’s development plan: modification to current completion designs to achieve greater near-well fracture complexity and modification of targeting strategies to more-effectively drain the Eagle Ford interval. Methodology To evaluate these approaches, the company acquired multiple data sets to provide an integrated study. An already developing and productive area was selected in southwest Texas to examine completion design and targeting strategies while attaining a data set to allow for complex completion monitoring and reservoir simulations to aid in subsequent development optimization while maintaining at least type-curve production. Microseismic was acquired on three wells with multiple downhole arrays used to visualize how fracture geometries were affected by completion design changes. For quality control, data from ultrasonic image tools, cement-bond logs, and gyros were acquired to increase confidence in microseismic results. Time-lapse 2D lines were acquired pre- and post-hydraulic fracture to measure seismic changes induced by completions. Water- and oil-soluble tracers were run to determine hydraulic fracture extent and drainage footprint. Parent wells were instrumented with surface pressure gauges to characterize hydraulic fracture hits. With permanently installed fiber, a post-hydraulic fracture downhole camera was run to examine cluster efficiency per completion design. Core and quad-combo logs were taken in the area to analyze compositional similarities in oil signatures compared with produced oil and to calibrate petrophysical and geomechanical values. Oil samples were collected and analyzed to derive an equation of state for fluid characterization and reservoir simulation. Natural fracture characterization was performed to determine the pre-existing geological fabric of the rock using lateral electrical borehole images, a field outcrop study, and quad-combo and fracture-identification logs derived from drilling data. Multiple facture calibration tests were collected in the study area at different target intervals to calibrate vertical stress profiles and examine reservoir pressures. Lastly, following 1 year of production, a temporary rod-conveyed fiber-optic production log was run to determine cluster contribution based on completion design. The independent data sets were integrated on a common commercial software platform for geomodel creation, discrete natural fracture characterizations, hydraulic fracture simulations, and reservoir simulations. An integration strategy was developed to bring together the vast amount of data acquired. The work flow is a simplified representation of the data interdependencies and was used throughout the study. Only five data acquisitions are shown to overlap; however, any change in interpretation can lead to revision and iteration of several interdependent segments.

Geological Risk Calculation through Probability of Success (PoS), Applied to Radioactive Waste Disposal in Deep Wells: A Conceptual Study in the Pre-Neogene Basement in the Northern Croatia

The basic principles of geological risk calculation through probability of success (PoS) are mostly applied to numerical estimation of additional hydrocarbon existence in proven reservoirs or potential hydrocarbon discoveries in selected geological regional subsurface volumes. It can be adapted and validated for a comprehensive input dataset collected in the selected petroleum province, by dividing up geological events into several probability categories and classes. Such methodology has been widely developed in the last decades in the Croatian subsurface—mostly in the Croatian Pannonian Basin System (CPBS). Through the adaptation of geological categories, it was also applied in hybrid, i.e., stochastic, models developed in the CPBS (Drava Depression), mostly for inclusion of porosity values. As the robustness of this methodology is very high, it was also modified to estimate the influence of water-flooding in increasing oil recovery in some proven Neogene sandstone reservoirs in the CPBS (Sava Depression). This new modification is presented to be applied to geological risk calculation, intending to assess the safety of geological environment storage in deep wells, where spent nuclear fuel (SPN) would be disposed, a subject of great importance. The conceptual study encompassed the magmatic and metamorphic rocks in the pre-Neogene basement of the CPBS, intended to be used for such purpose. Regionally distributed lithologies are considered for nuclear waste disposal purpose, in order to detect the safest ones, considering petrophysical values, water saturation, recent weathering and tectonic activity.

Digital Rock Segmentation for Petrophysical Analysis With Reduced User Bias Using Convolutional Neural Networks

AbstractPore‐scale digital images are usually obtained from microcomputed tomography data that has been segmented into void and grain space. Image segmentation is a crucial step in the process of digital rock analysis that can influence pore‐scale characterization studies and/or the numerical simulation of petrophysical properties. This is concerning since all segmentation methods have user‐selected parameters that result in biases. Convolutional neural networks (CNNs) provide a way forward since once trained, CNN can provide consistent and reliable image segmentation with no user‐defined inputs. In this paper, a CNN is used to segment digital sandstone data, and various ground truth data sets are tested. The ground truth images are created based on high‐resolution microcomputed tomography data and corresponding scanning electron microscope data. The results are evaluated in terms of porosity, permeability, and pore size distribution computed from the segmented data. We find that watershed‐based segmentation provides a wide range of possible petrophysical values depending on user‐selected thresholds, whereas CNN provides a smaller variance when trained on scanning electron microscope data. It can be concluded that CNN offers a reliable and consistent way to segment digital sandstone data for petrophysical analyses.

Evaluation of Abu Madi Formation in Baltim North & East gas fields, Egypt, using seismic interpretation and well log analysis

ABSTRACT Abu Madi Formation is a gas fertile rock unit in Nile Delta basin and the main gas production rocks in Baltim fields which located in the Mediterranean sea, north of Baltim city, Egypt. This rock unit in the study area contains two gas productive sand zones; these are zone III main and zone III lower. The lithologic components of Abu Madi Formation that defined from the dia-porosity (density–neutron) cross-plot and the tri-porosity (RHOMAA–DTMAA) cross-plot, showing that, Abu Madi Formation consists mainly of sandstone, shale, shaly sandstone in some parts and calcareous material. The resultant petrophysical parameter values, revealed that, both zone III main and zone III lower in the area under investigation show potential in their petrophysical characteristics, as a fertile gas reservoir. Zone III lower shows the most advanced petrophysical characterisation as a desired reservoir, with lower value of shale volume of 4%, good effective porosity of 17% and higher value of hydrocarbon saturation of 70%. Finally, these reservoirs are bounded by two normal faults with remarkable displacement. The first fault located at south, strike E - W and dips toward the North, the other fault located north, trending NE- SW and dips to the north.

Seismic‐impedance inversion with fuzzy clustering constraints: an example from the Carlin Gold District, Nevada, USA

ABSTRACTThe seismic reflection method provides high‐resolution data that are especially useful for discovering mineral deposits under deep cover. A hindrance to the wider adoption of the seismic reflection method in mineral exploration is that the data are often interpreted differently and independently of other geophysical data unless common earth models are used to link the methods during geological interpretation. Model‐based inversion of post‐stack seismic data allows rock units with common petrophysical properties to be identified and permits increased bandwidth to enhance the spatial resolution of the acoustic‐impedance model. However, as seismic reflection data are naturally bandlimited, any inversion scheme depends upon an initial model, and must deal with non‐unique solutions for the inversion. Both issues can be largely overcome by using constraints and integrating prior information. We exploit the abilities of fuzzy c‐means clustering to constrain and to include prior information in the inversion. The use of a clustering constraint for petrophysical values pushes the inversion process to select models that are primarily composed of several discrete rock units and the fuzzy c‐means algorithm allows some properties to overlap by varying degrees. Imposing the fuzzy clustering techniques in the inversion process allows solutions that are similar to the natural geologic patterns that often have a few rock units represented by distinct combinations of petrophysical characteristics. Our tests on synthetic models, with clear and distinct boundaries, show that our methodology effectively recovers the true model. Accurate model recovery can be obtained even when the data are highly contaminated by random noise, where the initial model is homogeneous, or there is minimal prior petrophysical information available. We demonstrate the abilities of fuzzy c‐means clustering to constrain and to include prior information in the acoustic‐impedance inversion of a challenging magnetotelluric/seismic data set from the Carlin Gold District, USA. Using fuzzy c‐means guided inversion of magnetotelluric data to create a starting model for acoustic‐impedance proved important in obtaining the best result. Our inversion results correlate with borehole data and provided a better basis for geological interpretation than the seismic reflection images alone. Low values of the acoustic impedance in the basement rocks were shown to be prospective by geochemical analysis of rock cores, as would be predicted for later gold mineralization in weak, decalcified rocks.

Petrophysical “Big Data” - case study from the Stavely Project, western Victoria

SummaryThe application of recent technological advances to the acquisition of petrophysical datasets has significantly increased the amount of quality, systematic physical rock property measurements that can be captured efficiently and cost effectively. These large datasets provide a more comprehensive understanding of petrophysical values and, as importantly, their statistical distribution – particularly when encompassing a diverse set of rock types and stratigraphy. To date, these types of comprehensive datasets are limited in the mineral exploration space, in both number and their spatial distribution.This paper presents a case study from the Stavely Project area in western Victoria outlining the workflow from acquisition, compilation and analysis, to the application of a large, pre-competitive petrophysical dataset. These data, including gamma density, magnetic susceptibility, P-wave velocity, electrical resistivity and natural gamma, were acquired by scanning of diamond core from 21 stratigraphic and mineral exploration drill holes by Multi-Sensor Core Logger equipment, providing a combined final dataset of 216,699 petrophysical values. The precompetitive data and subsequent analyses are available for download.In developing a statistical analysis of the petrophysical values, the datasets were segregated into stratigraphic, lithological and spatial sub-populations, therefore giving a geological context for the data, and providing baseline values for regional geophysical interpretations, forward modelling and inversions, and the identification of regions of anomalous petrophysical values potentially associated with hydrothermal mineralisation. Crosscorrelation of various petrophysical properties highlights important relationships within the data, thus maximising its value. In western Victoria these data have been important in the delineation of prospective volcanic belts of the Stavely Arc beneath cover, and the development of a 3D model displaying the regional geometries and distributions of the belts at depth.

Pore space properties in carbonate fault rocks of peninsular Italy

The fault cores of extensional faults in Mesozoic limestones and dolostones are examined by mean of combined microstructural, ultrasonic and petrophysical analyses. Grain-supported fault rocks commonly localize in the outer fault cores, whereas matrix-supported fault rocks in their inner portions. Cemented fault rocks, if present, surround the main slip surfaces. All dolomite-rich fault rocks, include elongated pores that show a preferential orientation only in the inner fault core. On the contrary, the pore network of calcite-rich fault rocks is made up of elongated pores in the outer fault core, and of sub-spherical pores in the inner fault core. Despite their different pore network characteristics, the petrophysical values of both grain-supported and matrix-supported fault rocks are quite similar one another, with effective porosity up to 10–12%, and permeability up to 2–5 mD. Differently, these values drop down to host rock values, porosity ~5% and permeability ~10−3 mD, in the cemented fault rocks. Experimental data are discussed to establish, for the first time, the relative control exerted by individual cataclastic and diagenetic processes on the present day pore characteristics, and to decipher the fault core permeability structure at depth.

Investigation of reservoir characteristics, depositional setting and T\u2013R sequences of the Lockhart Limestone of Meyal Oil Field, Pakistan: a petrophysical approach

The present study is focused on formation evaluation of the Lockhart Limestone in two wells (Meyal-05P and Meyal-10P) located in Northern Deformed Potwar Zone of the Potwar sub-basin, Pakistan. The geological formations ranging from Triassic to Pliocene have been drilled in these wells. The formation evaluation of the Lockhart Limestone mainly involves reservoir potential evaluation, interpretation of depositional environment and transgressive–regressive sequences using petrophysical logs. In either wells, the reservoir characterization is steered by various petrophysical parameters including calculation of volume of shale, porosity, permeability and hydrocarbon saturation. The thickness of the Lockhart Limestone is 50 m and 77 m in the Meyal-05P and Meyal-10P wells, respectively. In Meyal-05P and Meyal-10P wells, the average petrophysical parameters values and ranges are given as follows: volume of shale 48% and 20%; density porosity 1–5.6% and 1–31.7%; neutron porosity 1–23% and 1–42.9%; sonic porosity 1–29% and 1–39%; effective porosity < 1–> 5% and 1–21%; and hydrocarbon saturation 92.21–99.8% and 97–99.6%. The petrophysical parameters indicate that the Lockhart Limestone of Meyal-10P well is quantitatively better reservoir than that of the Meyal-05P. In Lockhart Limestone of either wells, the permeability is < 0.1 mD. The bulk volume water deciphered the presence of vuggy and intercrystalline porosity in the Lockhart Limestone. Similarly, the lithological interpretation using logs shows mainly limestone with minor shales. Different electrofacies are interpreted from the log trends of gamma ray log such as aggrading, prograding and retrograding depositional sequences deposited in tidal channel fill, shallow water, shore line and offshore buildup and regressive-to-transgressive shore face depositional setting.

Evaluation of hydrocarbon reserves using integrated petrophysical analysis and seismic interpretation: A case study of TIM field at southwestern offshore Niger Delta oil Province, Nigeria

This study presents the log analysis results of a log suite comprising gamma ray (GR), resistivity (LLD), neutron (PHIN), density (RHOB) logs and a 3D seismic interpretation of TIM field located in the southwestern offshore of Niger Delta, Nigeria. This study focuses essentially on reserves evaluation of hydrocarbon-bearing sands. Well data were used in the identification of reservoirs as well as hydrocarbon presence and determination of petrophysical parameters. Three horizons that corresponded to selected sands tops (sand D, sand E, and sand F) were mapped after well-to-seismic tie. The three horizons marked the tops of reservoir sands and provide the structures for hydrocarbon accumulation. Structural depth maps were created from the mapped horizons. The structural style is dominated by widely spaced simple rollover anticline bounded by growth faults, and this includes down-to-basin faults, antithetic faults and synthetic faults. The petrophysical values – the porosity, net-to-gross, water saturation, hydrocarbon saturation that were calculated yielded an average porosity value of 0.23, water saturation value of 0.32 and an average net-to-gross value of 0.62. Hydrocarbon in-place was evaluated. The total hydrocarbon proven reserves for the mapped horizons (sand D, sand E, and sand F) were evaluated to be 39.04MMBO of oil, and 166.13BCF of gas for sand E.

Three-dimensional characterisation of sedimentary heterogeneity and its impact on subsurface flow behaviour through the braided-to-meandering fluvial deposits of the Castissent Formation (late Ypresian, Tremp-Graus Basin, Spain)

Abstract Fluvial deposits of the Castissent Formation (late Ypresian) form part of the Eocene infill of the Tremp-Graus piggyback basin. The Castissent Formation has been subdivided into three complexes (A, B, and C). This project focuses on the proximal fluvial-sandstones of Complex A in the Mas de Faro outcrop (NE Iberian Peninsula). There, three amalgamated channel belts are exposed in a 15–24 m thick succession that passes upwards from sandy braided-river deposits (A1-A2) to coarse-grained meandering-river deposits (A3). Sedimentary heterogeneities within these deposits are characterised and their impact on oil recovery in a reservoir analogue are estimated using field descriptions, virtual outcrop interpretation, a 3D geocellular facies model and fluid-flow simulations. Petrophysical values of different facies types were derived from well data through analogous fluvial deposits of the Eiriksson Formation, in the Norwegian North Sea. Facies analysis show a waning succession of gravel channel lags, unit-bar and dune deposits in A1; a basal mud-clast channel lag, unit-bars and dune deposits in A2, and a coarse-grained point-bar succession in A3. Flow simulation shows: a) fingering of the waterfront related to the gravel channel lag and unit-bars of A1 and A2, and the gravel bars, scour-and-fill deposits and dunes of A3, which act as thief zones hindering efficient sweeping of the intervals immediately above; b) segregation of the injected fluids towards the base of the channel belts due to the fining-upwards successions; and c) vertical compartmentalization due to a relatively impermeable barrier at mud-clast channel lag beds. Permeability contrasts trapped 35% of the original oil in place after 0.5–0.6 pore volumes were injected.

Hydrocarbon Reservoir Evaluation: a case study of Tymot field at southwestern offshore Niger Delta Oil Province, Nigeria

Abstract: Aim: This study presents the log analysis results of a log suite comprising gamma ray (GR), resistivity (LLD), neutron (PHIN), density (RHOB) logs and a 3D seismic interpretation of Tymot field located in the southwestern offshore of Niger delta. This study focuses essentially on reserves estimation of hydrocarbon bearing sands. Well data were used in the identification of reservoirs and determination of petrophysical parameters and hydrocarbon presence. Three horizons that corresponded to selected well tops were mapped after well-to-seismic tie. Structural depth maps were created from the mapped horizons. The structural style is dominated by widely spaced simple rollover anticline bounded by growth faults, and this includes down-to-basin faults, antithetic faults and synthetic faults. The petrophysical values – the porosity, net-to-gross, water saturation, hydrocarbon saturation that were calculated yielding an average porosity value of 0.23, water saturation of 0.32 and an average net-to-gross value of 0.62. Three horizons H1, H2 and H3 were mapped. The three horizons marked the tops of reservoir sands and provide the structures for hydrocarbon accumulation. Hydrocarbon in-place was estimated. The total hydrocarbon proven reserves for the mapped horizons H1, H2, and H3 were estimated to be 39.04MMBO of oil and 166.13BCF for sand E.