Routine Core Analysis Research Articles

Subsurface Characterization for Secure CO2 Storage in the Pennsylvanian-permian Storage Complex in the Midcontinent Region, U.S.A.

Subsurface characterization of target injection and confining zones is essential for developing a safe and successful Carbon Capture Utilization and Storage (CCUS) project. The Integrated Midcontinent Stacked Carbon Storage Hub (IMSCS-HUB) Project is assessing the feasibility of commercial-scale CCUS implementation in the Midcontinent Region of the United States of America (USA) as part of the U.S. Department of Energy-National Energy Technology Laboratory’s (DOE-NETL) Carbon Storage Assurance Facility Enterprise (CarbonSAFE) initiative. The IMSCS-HUB project area is comprised of a carbon dioxide (CO2) source corridor that runs from eastern Iowa to western Nebraska and a stacked CO2 storage corridor that spans across western Nebraska and Kansas, representing the first large-scale CCUS project for the Midcontinent Region. The deep saline reservoirs and caprocks of the IMSCS-HUB stacked storage corridor subsurface make up a Pennsylvanian-Permian Storage Complex which is characterized by thick stratigraphic successions of marine and non-marine sedimentary rocks, (i.e. cyclothems). These stratigraphic successions provide alternating sequences of deep saline formations, oil-bearing reservoirs, shale, and evaporite units that are conducive to vertically stacked CO2 injection for geologic storage and enhanced oil recovery (EOR). Selected areas within the IMSCS-HUB storage corridor have been identified for detailed CO2 storage site characterization in southwest-central Nebraska (Sleepy Hollow Site), in western Nebraska (Madrid Site), and in western Kansas (Patterson Site). As part of the IMSCS-HUB project, characterization wells were drilled, whole and sidewall core were acquired, advanced geophysical well logs were collected, and well testing was conducted the knowledge gaps at the selected storage sites. Regional and site-specific subsurface analyses of the Pennsylvanian-Permian Storage Complex in the Midcontinent Region are conducted to validate caprock integrity through stacked-injection simulations, and to inform the post-injection monitoring plan. The lateral and vertical extents of the formations of interest are defined through well log analysis and geologic mapping. The stress regime is defined using image log data, mini-fracture tests, and drill stem tests. Petrophysical and geomechanical properties of reservoir and caprock intervals are determined through core laboratory testing, advanced well log analysis (sonic and image logs), and well testing (mini-fracture and drill stem tests). The well testing data is also used to determine the fracture pressure gradient/injection pressure constraints. The core laboratory testing includes routine core analysis (porosity, permeability, net confining stress, and grain density), mercury injection capillary pressure, effective permeability, threshold entry pressure, and triaxial compressive strength. The results of the subsurface characterization are used to construct and populate the static earth model and are key inputs for stacked-injection simulations. Three-dimensional simulations assess the baseline stresses in the subsurface and provide information on the fracture gradient to estimate the maximum permissible injection pressure, simulate the mechanical integrity of the caprocks, and evaluate the risk of induced seismic events using an injection scenario of 50 million metric tons, per the CarbonSAFE objective. The IMSCS-HUB project is supported by the U.S. Department of Energy-National Energy Technology Laboratory Agreement No. DE-FOA-0031623.

Challenges in the Petrophysical and Dynamic Characterization of Deepwater Turbidite Deposits of the Colombian Caribbean Offshore–A Case Study

The Colombian Caribbean region has become an important exploratory target, and recent discoveries confirm its potential as a gas province to overcome the expected near-future gas deficit. A petrophysical and dynamic characterization workflow was implemented for this challenging deepwater play, where the depositional environment is the result of turbidity current processes. The reservoirs consist mostly of thin to very thin sand layers, corresponding mainly to the Ta, Tb, and Tc divisions of the Bouma sequence as observed in the cored intervals. Bouma divisions Td and Te are related with the lowest rock quality and represent the nonreservoir intervals. The greatest challenge in the characterization of this particular reservoir is the vertical resolution, given the very low thickness of the layers, which becomes very difficult to detect using standard resolution logs. Thus, tomography images, resultant CT-scan curves, and their integration with routine and special core analyses were used to reveal the true nature of this complex reservoir. The proposed methodology focuses on the integration of routine and special core analysis for the petrophysical and dynamic characterization of the reservoir, where the pore-throat-radius distribution from high-pressure mercury injection becomes the basis of the differentiation between what is considered reservoir and what is not. Pore-throat radius estimated from high-pressure mercury injection (R35) correlates extremely well with textural features and clay content in the rock; therefore, this parameter (R35) was used to define the different classes for rock typing. The approach taken was to develop a multilinear regression model of R35 as a function of very high-resolution tomography outputs in the cored zones and then see how it may be extrapolated to the uncored zones using available high-resolution logs. Special petrophysical analyses, such as NMR low field, porous-plate capillary pressure, electrical properties, and relative permeability curves (steady state), showed correlation with the defined rock types and, in turn, allowed for a determination of the gas accumulation potential of the area. Finally, rock and fluid (dry-gas) properties have been used to build a single-well radial model to design initial well tests (DST) and predict production performance from each interval (selective tests). The simulation model represents the lateral and vertical heterogeneity related to the geological environment (turbidites). The final results have defined the flow and shut-in times during tests to optimize the budget.

A new method to improve the NMR log interpretation in drilling mud-invaded zones: A case study from the Brazilian Pre-salt

The Santos Basin hosts several giant carbonate oilfields in the Pre-salt province and is one of the most important hydrocarbon discoveries in the past years. These carbonate reservoirs present exceptional reservoir quality with a challenging depositional and diagenetic history that produced complex and heterogeneous pore systems. As one of the most effective tools for in-situ porosity and permeability evaluation, the nuclear magnetic resonance (NMR) well log plays an essential role in the Pre-salt petrophysical evaluation and its signal interpretation must be performed carefully. This work proposes a new approach to detect and improve the interpretation of zones with unreal NMR logging tool readings in areas heavily affected by drilling mud invasion in caverns/vugs, which causes a T2 distribution shift towards lower relaxation times. This work analyses well log data from 28 wells in the Sapinhoá Field, supported by special core analyses (SCAL) and routine core analyses (RCAL), as well as plugs, sidewall cores and thin sections data. The proposed approach generates synthetic NMR Free Fluid and T2 distributions with minimum error and replaces the faulty data, consisting in five main steps, (1) computing new curves to be used as inputs; (2) detecting the zones affected by the invasion; (3) water saturation calculation by the saturation height modeling method; (4) calculating a synthetic NMR free fluid curve based on a relationship between a NMR-derived water saturation and the saturation height model; and (5) using the Random Forests algorithm to estimate a synthetic T2 distribution. The proposed method has a minimized error and resulted an increase of up to 10% thickness in the pay zone and a reduction of up to 9% in water saturation average, which may represent enormous amounts of oil depending on the reservoir area. This study provides a new method, which can be used in the improvement of petrophysical interpretations in highly heterogeneous carbonate reservoirs and thus reducing the exploratory and development risks. • Drilling mud invades vug pores and results in misleading NMR readings; • A new methodology is proposed to create a synthetic NMR free fluid and T2 distribution with minimum error; • An increase of 10% in pay thickness and a reduction of 9% in average water saturation was achieved in the Pre-salt reservoirs; • The methodology is proper for the petrophysical evaluation of highly heterogeneous carbonate reservoirs

Sensitivity of Digital Rock Method for Pore-Space Estimation to Heterogeneity in Carbonate Formations

Summary With advancements in technology and computational capacity, the method of digital rock physics (DRP) for characterizing the storage and flow properties of a reservoir is gradually taking up the space that was once dominated by conventional methods such as routine core analysis (RCA) and special core analysis (SCAL). Unlike RCA and SCAL, the DRP method provides a nondestructive approach to deal with the core samples, which in a way is also more repeatable, economic, and is a clear improvement over the existing conventional methods in terms of its flexibility to experience the multiphysics of the rock and fluids. However, DRP still has some lacunae because the available algorithms have limitations in handling various challenges of complex lithology, such as grain/pore-boundary transition, soft/hard-matter transition, and imprints of intensity gradients of a 3D structure on 2D slices. Therefore, in this paper, we proposed a new approach to handle multiple issues by optimizing the segmentation algorithms and putting them together to standardize workflows (WFs) for reliable determination of the pore volume (PV), which could be verified with the field observation of porosity obtained using industry-standard laboratory methods and well logs. More emphasis was placed on the adaptability of the WF to deal with varying heterogeneity in the rocks. In this work, we proposed five WFs and compared them with the standard algorithms (including edge detections, watershed, and global thresholding) in terms of accuracy and computation time for a set of four homogeneous and four heterogeneous samples. We found that WF3 was the one that consistently performed better than all other WFs and some of the popular algorithms when compared one to one. We used a data-conditioning filter, contrast-limited adaptive histogram equalization (CLAHE)—a practice used in medical imagery—for local contrast enhancement in the heterogeneous carbonates to increase the signal/noise ratio of the rock-sample images. It successfully handled the contrast variability caused by the pockets of low illumination in the heterogeneous samples. Its limitation has also been detailed in the paper.

Barnicarndy Graben, southern Canning Basin: stratigraphy defined by the Barnicarndy 1 stratigraphic well

Funded by Geoscience Australia’s Exploring for the Future initiative and operated by the Geological Survey of Western Australia, the Waukarlycarly 1 deep stratigraphic drillhole was designed to investigate the geology of the little-known Waukarlycarly Embayment and assess the petroleum, mineral, groundwater and CO2 storage potential of the area. Based on consultation with the Western Desert Lands Aboriginal Corporation on the cultural significance of the name, Waukarlycarly, it has been agreed to change the name of the well to Barnicarndy 1 and the tectonic subdivision to the Barnicarndy Graben. This and all future publications will now refer to the Barnicarndy 1 stratigraphic drillhole (previously Waukarlycarly 1) and the Barnicarndy Graben (previously Waukarlycarly Embayment). Drilling commenced on 1 September 2019 and reached a total depth (TD) of 2680.53m on 30 November 2019, recovering more than 2km of continuous core. The cored interval extended from 580m to TD in Neoproterozoic Yeneena Basin dolostone, which was unconformably overlain by a thick, lower Canning Basin Ordovician stratigraphy, including richly fossiliferous marine mudstones with common volcanic ash beds. A major unconformity is located at the top of the Ordovician section where it is overlain by sandstones and muddy diamictites of the Carboniferous–Permian Grant Group, followed by a Cenozoic succession near surface. Ditch cuttings were collected from surface to 580m at 3m intervals. The pre-Grant Group Paleozoic succession is unique within the Canning Basin, indicating that the Barnicarndy Graben’s depositional history is markedly different when compared with adjacent structural subdivisions, such as the Munro Arch and Kidson Sub-basin. Detrital zircon geochronology, biostratigraphy and borehole imaging interpretation assisted in the definition of two new geological units within the Ordovician stratigraphy of Barnicarndy 1: the Yapukarninjarra and Barnicarndy formations. Preliminary routine core analysis data indicates the potential for CO2 storage within the Barnicarndy Formation beneath a Grant Group seal. The well also provides new insights into the structural interpretation of the Barnicarndy Graben.

Reservoir petrofacies — A tool for characterization of reservoir quality and pore structures in a tight sandstone reservoir: A study from the sixth member of Upper Triassic Yanchang Formation, Ordos Basin, China

Reservoir petrofacies is an important tool for the better understanding of the key petrographic parameters (primary texture and detrital component, types and processes of diagenetic alteration) that control reservoir properties of tight sandstones. This study aims to investigate sandstone texture and composition, and diagenetic features of the sixth member of Upper Triassic Yanchang Formation (YC6 member), Ordos Basin, China, and to examine controls of diagenesis and petrofacies on reservoir quality and pore structures of tight sandstone reservoirs. This study has been carried out using petrography, XRD, SEM, routine core analysis and mercury intrusion capillary pressure (MICP) test. The YC6 member sandstones are moderately well sorted, very fine- to fine-grained arkoses. The reservoir quality and pore throat distributions are highly heterogeneous in the sandstones. Four reservoir petrofacies are defined based on the combination of sandstone detrital components, diagenetic processes, pore types and reservoir properties. Contrasting diagenetic characteristics between these petrofacies are mainly determined by detrital grain size through ductile grain compaction. Ductile grain compaction has a significant control on porosity and permeability of the sandstones. Especially, the poor quality has been encountered in the petrofacies where ductile grain content is >12%. Calcite cement has helped destroy quality of the petrofacies where the cement is present in amounts >15%. Reservoir quality is best for the petrofacies that is poor in both ductile grain and calcite cement and commensurately is rich in secondary dissolution. Four pore-facies types are defined based on the dominant pore throat dimension of the sandstones. The large pore-throat regime determines permeability and fluid flow of reservoir rocks. A good correlation between pore-facies and petrofacies indicates diagenetic effect on pore structures of the sandstones. The study provides insights into how reservoir quality and pore structures of tight sandstone reservoirs are correlated with reservoir petrofacies.

ROCK QUALITY GROUPING IN SANDSTONE FORMATION USING A CRITICAL POROSITY APPROACH AT FORMATION PRESSURE CONDITIONS

The methods of grouping reservoir rock types based on the physical properties of rocks that have been studied by previous researchers still have a relatively large value of uncertainty. This uncertainty arises in conditions where rock type grouping is carried out in wells that do not have core sample data. Where we know that in the oil and gas field, not all wells in the field are subjected to rock sampling, either routine core analysis or special core analysis. From these problems, the authors feel the need to carry out this study to create a method for classifying reservoir rock types based on the physical properties of rocks that can be used in wells that do not have core sample data. The rock types in the wells that do not have core samples will be grouped based on the critical porosity value of the rock obtained from the vp value in the acoustic log data owned by these wells. By making an approach model through the critical porosity of rocks from wells that have core sample data, wells that only have acoustic log data can be grouped by using the critical porosity approach which is generated from the vp value of the acoustic log.

Prediction of cementation factor for low-permeability Iranian carbonate reservoirs using particle swarm optimization-artificial neural network model and genetic programming algorithm

cementation factor is a crucial parameter that has a significant influence on the estimation of reservoir parameters. Laboratory measurements for cementation factor are available for occasional cases because experimental special core analyses for determination of cementation factor values are expensive and time-consuming. While this factor plays a significant role in determining water saturation, there is no comprehensive and precise relationship for the case of Iranian carbonate reservoirs. In this article, a unique model was used based on a powerful combination of artificial neural network (ANN) and particle swarm optimization (PSO) algorithm to model the cementation factor. In the second phase of simulation, a correlation for the cementation factor was discovered by genetic programming (GP) algorithm. Both the PSO-ANN model and GP algorithm are trained by input variables such as porosity, permeability, and grain density derived from 175 routine core analysis (RCAL) samples of 21 carbonated oil fields. To determine the relative impact of the independent variables on cementation factor the sensitivity analysis was carried out for both models. The comparison between the PSO-ANN model output and the experimental cementation factor data clearly demonstrated that the built model can predict the cementation factor with great precision; the mean square error between the model predictions and the experimental data was less than 0.07. The root mean square error of training and testing data sets for the new developed correlation using GP algorithm were 0.0902 and 0.0727 respectively. Finally, to evaluate the validity and reliability of the developed models, a comparison was implemented between these two models and other empirical models over an external employment data set (21 data point). This comparison revealed that the GP algorithm and PSO-ANN model deliver a higher performance capacity compared to other proposed correlations for predicting cementation exponent.

Pore structure, fractal characteristics and permeability prediction of tight sandstones: A case study from Yanchang Formation, Ordos Basin, China

Many fractal models have been proposed based on mercury intrusion porosimetry (MIP) for investigating the fractal property of porous materials. However, results calculated from different fractal models may be not always consistent according to previous works. In view of this, a combination of techniques including routine core analysis, MIP analysis and images analysis (thin sections and BSE) was used to study the pore structure and petrophysical properties of tight sandstones. The results of pore structure and petrophysical properties were used to check whether the fractal dimension values from five popular MIP fractal models can represent the heterogeneity of tight sandstones.It turned out that different MIP fractal models usually give different results. A single fractal dimension value representative of the entire range of pore sizes can be obtained by either Zhang and Li's model or Shen and Li's model. As fractal dimension increases, pore structure becomes more complex and permeability decreases. However, permeability or pore structure shows no significant correlation with fractal dimensions obtained from other models (Neimark's, Li's and Friensen and Mikula's model) by zone analysis. Nevertheless, two fractal regions can be identified by Neimark's or Li's model and clear inflection points could be identified on the fractal curves. The inflection points are found to be almost equal to the apex determined by Pittman's method, and could be regarded as good indicators for permeability prediction. The results obtained from Friensen and Mikula's model is more complex, and not very satisfactory to describe the heterogeneity for tight sandstones.

Petrophysical Correlations for the Permeability of Coquinas (Carbonate Rocks)

The pore structure of many carbonate formations is known to be very complex and heterogeneous. Heterogeneity is manifested by the presence of different types, sizes, and shapes of pores resulting from sedimentation and diagenetic actions. These complexities greatly increase uncertainties in estimated rock hydraulic properties in that different permeability values may occur for samples having similar porosities. In order to understand the effects of pore structure and heterogeneity, petrophysical analyses were performed on coquina samples from the Morro do Chaves Formation (Barremian, Sergipe-Alagoas Basin), which is an analogue of Brazilian Pre-salt oil reservoirs of Itapema Formation in the Santos Basin. Routine core analyses, and NMR and MICP measurements were carried out to obtain pore body and pore throat distributions. Obtained T2 relaxation times were converted to pore size radii by matching the NMR and MICP curves. Pore-scale imaging and pore network modelling were performed using microCT scans and the PoreFlow software, respectively. Calculated permeabilities using PoreFlow showed excellent agreement with the routine laboratory measurements. Samples having pore bodies with a higher coordination number showed much larger permeabilities at similar porosities. This study includes a statistical analysis of various features that caused the observed differences in permeability of the coquinas, including the role of connectivity of the entire porous system. Limitations and challenges of the various techniques, and the imaging and pore-scale flow simulations, are discussed.

Pore-throat structure characteristics and its impact on the porosity and permeability relationship of Carboniferous carbonate reservoirs in eastern edge of Pre-Caspian Basin

Abstract Carboniferous carbonate reservoirs at the eastern edge of the Pre-Caspian Basin have undergone complex sedimentation, diagenesis and tectonism processes, and developed various reservoir space types of pores, cavities and fractures with complicated combination patterns which create intricate pore-throats structure. The complex pore-throat structure leads to the complex porosity-permeability relationship, bringing great challenges for classification and evaluation of reservoirs and efficient development. Based on the comprehensive analysis on cores, thin sections, SEM, mercury intrusion, routine core analysis and various tests, this paper systematically investigated the features and main controlling factors of pore-throats structure and its impact on the porosity-permeability relationship of the four reservoir types which were pore-cavity-fracture, pore-cavity, pore-fracture and pore, and three progresses are made. (1) A set of classification and descriptive approach for pore-throat structure of Carboniferous carbonate reservoirs applied to the eastern edge of the Pre-Caspian Basin was established. Four types of pore-throat structures were developed which were wide multimodal mode, wide bimodal mode, centralized unimodal mode and asymmetry bimodal mode, respectively. The discriminant index of pore-throat structure was proposed, realizing the quantitative characterization of pore-throat structure types. (2) The microscopic heterogeneity of pore reservoir was the strongest and four types of pore-throat structures were all developed. The pore-fracture and pore-cavity-fracture reservoirs took the second place, and the microscopic heterogeneity of pore-cavity reservoir was the weakest. It was revealed that the main controlling factor of pore-throat structure was the combination patterns of reservoir space types formed by sedimentation, diagenesis and tectonism. (3) It was revealed that the development of various pore-throat structure types was the important factor affecting poroperm relationship of reservoirs. The calculation accuracy of permeability of reservoirs can be improved remarkably by subdividing the pore-throat structure types. This study deepens the understanding of pore-throat structure of complicated carbonate reservoirs, and is conducive to classification and evaluation, establishment of precise porosity-permeability relationship and highly efficient development of carbonate reservoirs.

Analysis of the relationship between porosity and permeability in reservoir modeling using the petrophysical rock type approach

The carbonate reservoir is one of the reservoir characters found in hydrocarbon fields in Indonesia. Carbonate reservoirs have complex porosity and permeability relationships. So it is necessary to do a special reservoir character that is different from the siliciclastic reservoir. Efforts that can be made to assist the development of this hydrocarbon field are to analyze the reservoir character in more detail using the petrophysical rock type (PRT) approach. This approach is used by combining geological elements such as the depositional environment, the petrophysical properties of the rock, as well as the fluid flow in it which is reflected by capillary pressure and water saturation. Modeling with this method is expected to be a method that can increase hydrocarbon production optimally in Xena Field. The object of research from Xena Field is Zone A2 which is included in the Parigi Formation. The Parigi Formation is one of the main hydrocarbon-producing reservoirs. The data used in this study are routine core analysis (RCAL) rock data on JLB-07, JLB-08, JLB-02, JLB-23 wells, wire log data (gamma-ray log, resistivity log, density log, neutron log) of 30 wells, and 2D seismic data. The depositional facies are divided into 2 facies, namely the margin reef platform facies and the interior platform facies. Identification of rock type (RT) using the flow zone indicator (FZI) method. The rock type in this field can be divided into 4 rock types, namely RT 1, RT 2, RT 3, RT 4 with RT 1 being able to drain the best fluid and RT 4 to drain the worst fluid. Reservoir property modeling is controlled by facies and rock type (RT) models. The margin reef platform facies are associated with RT 1 and RT 2. The interior platform facies are associated with RT 2 and RT 3.

Predicción de la porosidad a partir de registros de tomografía computarizada de rayos X (RHOB y PEF) usando Redes Neuronales Artificiales (ANN)

This work presents a method for rock porosity prediction from the X-ray computed tomography (CT) logs obtained using a double energy approach, bulk density (RHOB) and photoelectric factor (PEF). The proposed method seeks to correlate the known porosity from the Routine Core Analysis (RCAL) with RHOB and PEF high-resolution logs, as the response of these two measurements depends on the volumetric quantity of different rock materials and of the volume of its porous space. Artificial Neural Networks (ANNs) are trained so they can predict porosity from CT logs at a high resolution (0.625 mm). The ANNs validation and regression plots show that porosity predictions are good. High-resolution porosity models linked to CT images could contribute to enhancing the petrophysics model as they allow a more refined identification of intervals of interest due to the detailed measurement.

ВЫДЕЛЕНИЕ ПЕТРОФИЗИЧЕСКИХ ТИПОВ КАРБОНАТНЫХ ПОРОД ПО ДАННЫМ ЯДЕРНОГО МАГНИТНОГО РЕЗОНАНСА С УЧЕТОМ ИХ ЛИТОЛОГИЧЕСКИХ ОСОБЕННОСТЕЙ

Актуальность. Значительная часть мировых запасов углеводородов приурочена к карбонатным резервуарам, характеризующимся сложным строением пустотного пространства. Подсчет запасов и проектирование разработки таких залежей требуют детального изучения структуры пустотного пространства, которая напрямую определяет коллекторские свойства пород. Выделение петрофизических классов пород является неотъемлемой частью построения петрофизической модели залежи углеводородов. Метод ядерного магнитного резонанса (ЯМР) является одним из методов изучения структуры пустотного пространства горных пород и имеет ряд преимуществ перед другими методами. Однако в опубликованной литературе отсутствует информация о применении данного метода для решения задач петротипизации. Результаты выделения петрофизических классов на основе комплексирования данных ядерного магнитного резонанса и микролитологического описания шлифов позволят значительно улучшить качество петрофизического обеспечения геологического и гидродинамического моделирования залежи и, следовательно, повысить точность подсчета запасов углеводородов и эффективность их разработки. Цель: выделение петрофизических типов карбонатных пород на основе комплексирования данных ядерного магнитного резонанса и микроописания шлифов, а также оценка правильности выделения классов методами математической статистики. Объект: карбонатные породы формации Мишриф, являющейся продуктивной в разрезе одного из месторождений Месопотамской нефтегазоносной провинции. Методы: анализ результатов ЯМР-исследований образцов керна, микроописания шлифов и стандартных лабораторных исследований керна, методы математической статистики. Результаты. На основе комплексного анализа результатов ЯМР-исследований керна и микроописания шлифов выделены три петрофизических класса в разрезе изучаемой скважины, вскрывшей продуктивные отложения: образцы со структурами породы вакстоун и вакстоун/флаутстоун объединены в 1 класс, со структурами пакстоун, грейнстоун и рудстоун – во 2 класс, и со структурой фреймстоун – в 3 класс. Данная петротипизация подтверждена результатами статистического анализа.

Porosity system analysis and its relation to the permeability of the reservoir zones in the Upper Dalan Member and Kangan Formation: A case study, one of the gas fields in the Zagros Coastal Fars, SW Iran

The studied gas field is located in the Coastal Fars structural zone of the folded Zagros, in the west of Hormozgan Province and on the Gavbandi highland. The Dehram Group forms gas reservoirs in this field. The results of macroscopic and microscopic studies and routine core analysis of the Upper Dalan Member and Kangan Formation show that porosity with an average of 14.51% in the Kangan Formation is more than Upper Dalan Member with an average of 8.29% (certain intervals of the well cores); however, the Upper Dalan Member with an average of 10.8 md (10.8 × × 10−3 μm2) has higher permeability than Kangan Formation with an average of 3.54 md (3.54 × × 10−3 μm2). The Grain-supported facies (in accordance with Ka-2 reservoir zone) of the Kangan Formation has the best reservoir quality with an average of 10.7% effective porosity and 43.3% total water saturation; while in the Upper Dalan Member, mud-supported facies (in accordance with UDL-5 reservoir zone) has the best reservoir quality with an average of 10.2% effective porosity, and 36.7% total water saturation where the dolomitization process has been the most important factor for increasing the reservoir quality in these facies. The porosity type of the Kangan reservoir (oolitic grainstone of shoal facies belt in Ka-2 reservoir zone) is isolated moldic and vuggy those generates high porosity and low permeability values in this formation but in some intervals, the isolated molds and vugs are connected by channel and fracture; therefore increased the value of permeability. The tidal flat facies belt of Upper Dalan member has high porosity and permeability and good reservoir quality in the UDL-2, UDL-5 and UDL-6 reservoir zones, with respect to the tidal flat facies of the Kangan Formation, which is related to dolomitization processes that generate intercrystalline porosity type. Finally, both the depositional environment and diagenetic processes controlled the distribution characteristics of reservoir quality, as seen in the relation between porosity and permeability.

A new framework for selection of representative samples for special core analysis

Special core analysis (SCAL) measurements play a noteworthy role in reservoir engineering. Due to the time-consuming and costly character of these measurements, routine core analysis (RCAL) data should be inspected thoroughly to select a representative subset of samples for SCAL. There are no comprehensive guidelines on how representative samples should be selected. In this study, a new framework is presented for selection of representative samples for SCAL. The foundation of this framework is using methods of PSRTI, FZI∗ (FZI-star) and TEM-function for the early estimation of petrophysical static, dynamic, and pseudo-static rock types at RCAL stage. The global hydraulic element (GHE) approach is benefitted and a FZI∗-based GHE method (i.e., GHE∗) is presented for partitioning data. The framework takes into consideration different laboratory, reservoir engineering, geological, petrophysical and statistical factors. A carbonate reservoir case is presented to support our methodology. We also show that the current forms of Lorenz and Stratigraphic Modified Lorenz Plots in reservoir engineering are not appropriate, and present new forms of them.

Extraction of pore networks from thin section: A case study from deep marine turbidite outcrop

A reservoir should have pores that can accommodate fluid. This capability is supported by the petrophysical properties which reservoirs have. The petrophysical properties depends on how the sediments were deposited. This study is focused on the deep marine turbidite outcrop. Turbidity currents are a sedimentation process which makes the sediments carried randomly at high velocity and low viscosity. The petrophysical properties such as porosity and permeability could be determined using computational fluid dynamics (CFD) analysis and routine core analysis. The approaches of this study are to analyze the petrophysical properties using CFD analysis and compare the results with the routine core analysis. The samples of this study were nine thin sections collected from the outcrops, especially in the middle and the edges of the turbidite channel. These samples then processed in the CFD software called COMSOL Multiphysics thus the porosity and permeability of these samples could be determined. The results show that the porosity values of the CFD analysis are relatively similar with the routine core analysis has and the permeability values of the CFD analysis are higher than the routine core analysis has.

Reservoir quality derived from routine core analysis data of deep-water turbidite outcrop analogue

Turbidity current is a process where the fluid flows occurs as a turbulent flow where the molecules inside the fluid are moving randomly but with a net movement toward the orientation of the transport. The physical properties of turbidite deposit is highly impacted by the grain size distribution and rock texture during the deposition. The field in this study was an outcrop of Jatiluhur Formation which deposited by turbidity current on deep marine environment. The main goal of this study was to understand the correlation between the petro-physical properties of turbidite deposit with its depositional mechanism using the routine core analysis method. The samples in this study were collected from an outcrop and the routine core analysis data contains the percentage value of porosity and vertical permeability. The result of this study were the porosity was relatively equal to the permeability and depositional mechanism had a significant role in controlling the porosity and the permeability.

Qualitative and quantitative prediction of diagenetic facies via well logs

Drilled cores, thin section petrography, X-ray diffraction (XRD), scanning electron microscopy (SEM), routine core analysis (RCA), and mercury injection capillary pressure (MICP) tests were used to establish a predictable model for diagenetic facies and reservoir quality using well logs in sandstones of the Paleogene Dongying Formation in Nanpu Sag, Bohai Bay Basin, Eastern China. The results show that the sandstones are texturally and compositionally immature, and have primary intergranular pores, secondary intergranular and intragranular pores, moldic pores, and micro-pores associated with diagenetic clay minerals. The sandstones have undergone low to moderate mechanical compaction, but a high degree of framework-grain dissolution. Diagenetic minerals are dominantly of carbonates (calcite, dolomite, and Fe-dolomite) and clay minerals (illite, mixed layer illite/smectite and kaolinite). Four types of diagentic facies are recognized: tightly compacted, carbonate cemented, clay mineral filling, and dissolution facies. Porosity, permeability and oil saturation ranges among these diagenetic facies were determined from routine core analyses. The diagenetic facies were then translated to conventional well logs by core-log calibration, and the well log expressions (in terms of natural gamma ray, neutron porosity, bulk density, sonic transit time, and resistivity logs) of various diagenetic facies were summarized. The mineralogical composition obtained from the Elemental Capture Spectroscopy (ECS) logs was then used for the diagenetic facies prediction. The diagenetic facies predicted with the comprehensive conventional log analyses were combined with the ECS log profile, and were calibrated with the XRD, SEM analysis and logging interpretation results. For wells without ECS log, the diagenetic facies can be quantitatively predicted by the mathematical calculations of reservoir quality index (RQI) via the GR, AC and DEN log curves. Reservoir quality or oil bearing properties can be evaluated and predicted by translating the diagenetic facies to well logs.

Insights in the pore structure, fluid mobility and oiliness in oil shales of Paleogene Funing Formation in Subei Basin, China

Abstract Pore structure is an important factor influencing reservoir properties of oil shales. Routine core analysis, thin section, scanning electron microscope (SEM), mercury injection capillary pressure (MICP) tests, Nuclear Magnetic Resonance (NMR), and computed tomography (CT) were used to provide insights into the pore throat distribution in oil shales of member 2 of Paleogene Funing Formation (E1f2) in Subei Basin, China, with the special aim to unravel the effect of pore structure on fluid mobility and oiliness. The relationships between NMR parameters, petrophysical property and capillary parameters are investigated. The results show that rock composition in the oil shales consist of quartz, feldspar, carbonate particles, clay minerals and organic matters. Pore systems consist of large-scale interparticle pores, intragranular dissolution pores, and small-scale micropores within clay minerals and the organic matter pores. Four types of pore structure (Type Ⅰ, Type Ⅱ, Type Ⅲ and Type Ⅳ) are divided according to the patterns of capillary curves, capillary parameters, NMR T2 (transverse relaxation time) spectrum and BVI (bulk volume of immovable fluid) values. From Type Ⅰ to Type Ⅳ pore structure, the maximum mercury saturation (SHgmax) and mercury extrusion efficiency are decreasing, and the SHgmax are less than 50% averagely, indicating the oil shales are characterized by very poor pore connectivity. The T2 spectrum changes from bi-modal behavior to uni-modal and the right peaks become lower or even disappearing from Type Ⅰ to Type Ⅳ pore structure. Fluid mobility is not primarily controlled by pore size, but dependent on the content of short T2 components ( Pore structure controlled fluid mobility and determined the microscopic oiliness and macroscopic oil bearing property or hydrocarbon productivity. The comprehensive study above gains insights into the microscopic pore structure and their controls on fluid mobility and oiliness in shale oil reservoirs, and this may have implications for resource potential evaluation and effective exploitation of oil shales.