Shale Content Research Articles

A Novel Neural Network Prediction Model for Mineral Content Based on the Data of Elemental Logging and Well Logging

The mineral content of shale plays an important role in the study of reservoir characteristics. Obtaining high-precision mineral content data from a simple and straightforward method is helpful for the study of reservoir properties. Due to the complex and varied elemental combination of minerals and the lithological diversity in different formations, there are limitations in the traditional statistical methods for predicting mineral content. In this study, a multi-source fusion dataset is constructed first using a detailed workflow to process multi-source data from elemental logging and conventional well logging from the Funing shale formations in China. A hybrid neural network model consisting of a back-propagation artificial neural network (BP-ANN) and gated recurrent unit (GRU) structure, with a custom constraint loss function, is developed to predict the mineral contents. The results show that the predictive performance of this hybrid multi-source model performs statistically significantly better than that of the BP-ANN and GRU models using single source data. In addition, the accuracy of the hybrid model is further improved by using the custom constraint loss function. This method provides high-resolution distributions of mineral content compared to the X-ray powder diffraction testing method. It will help enhance the understanding of the formation.

Improvement of Sonic Logging Porosity Calculation Method in South Sulige Block

Abstract South Sulige Block is a lithologic gas reservoir with low porosity and permeability, low pressure and low abundance, of which the heterogeneity is very high and pore structure is complex. Due to the influence of lithology and pore structure, the skeleton value is uncertain and it is hard to give a fixed value. It is difficult to obtain the true porosity of formation accurately by using the traditional method of calculating porosity by Wyllie formula in sonic logging. In this paper, according to the principle of sonic logging and rock response characteristics, combined with core analysis data of this area and adjacent areas, using the acoustic time and core analysis porosity regression formula to calculate porosity first, and then, according to different shale content, the corresponding shale correction is carried out for heavy shale content intervals on the basis of core regression formula, which eliminates the porosity calculation error caused by the influence of shale content. Practical application shows that the porosity calculated by this method is in good agreement with the results of core analysis, and can reflect the reservoir characteristics and production capacity of the formation more truly.

Impact of Reservoir Heterogeneity on Bitumen Content in the Mackay River Oil Sands, Athabasca (Canada)

AbstractThe Lower Cretaceous Manville Group of Upper McMurray Formation is one of the main bitumen reservoirs in Athabasca. In this study, the relationship between reservoirs heterogeneity and bitumen geochemical characteristics were analyzed through core and microscopic observation, lab analysis, petrophysics and logging data. Based on the sedimentology framework, the formation environment of high‐quality oil sand reservoirs and their significance for development were discussed. The results indicate that four types lithofacies were recognized in the Upper McMurray Formation based on their depositional characteristics. Each lithofacies reservoirs has unique physical properties, and is subject to varying degrees of degradation, resulting in diversity of bitumen content and geochemical composition. The tidal bar (TB) or tidal channel (TC) facies reservoir have excellent physical properties, which are evaluated as gas or water intervals due to strong degradation. The reservoir of sand bar (SB) facies was evaluated as oil intervals, due to its poor physical properties and weak degradation. The reservoir of mixed flat (MF) facies is composed of sand intercalated with laminated shale, which is evaluated as poor oil intervals due to its poor connectivity. The shale content in oil sand reservoir is very important for the reservoir physical properties and bitumen degradation degree. In the context of regional biodegradation, oil sand reservoirs with good physical properties will suffer from strong degradation, while oil sand reservoirs with relatively poor physical properties are more conducive to the bitumen preservation.

Applicability of ensemble learning in total organic carbon and porosity evaluation of shales

Accurate evaluation of total organic carbon (TOC) content and porosity is of paramount significance for assessment and target interval selection for shale reservoirs. This study takes shales from the western Chongqing area as an exemplary case to delve into the applicability and reliability of ensemble learning in evaluating TOC content and porosity. The results indicate that although both Light Gradient Boosting Machine (LightGBM) and Random Forest (RF) algorithms are suitable for evaluating TOC content and porosity in shales, LightGBM algorithm is preferred due to its comprehensive advantages, including higher accuracy, stronger generalization capability, and faster operating speed. For TOC content evaluation, the four most important logging parameters identified by LightGBM and RF are consistent, but exhibit different orders: DEN (compensated density) > GR (gamma ray) > U (uranium) > CNL (compensated neutron) and DEN > U > GR > CNL, respectively. For porosity evaluation, LightGBM and RF identify the same type and order of the three most important logging parameters: AC (acoustic transit time) > DEN > U. This similarity may be attributed to the fact that both algorithms utilize Classification and Regression Tree (CART) as base learners. The dependence plots between SHAP (SHapley Additive exPlanations) values and logging parameters reveal that the role of each logging parameter in the evaluation model is segmented, rather than exhibiting a continuous linear contribution. In conclusion, given the exceptional performance of ensemble learning algorithms, they, especially LightGBM algorithm, are highly recommended for shale evaluation.

Mechanism Research and Identification Method of Low Resistivity Gas Layers in the M block of Algeria

Abstract The M block in Algeria is located in the southern Sahara platform, with oil and gas reservoirs mainly composed of river-glacial marine facies, fluvial and shallow marine fine sandstones. The pore structure is complex, and the difference in resistivity logging between gas layers and water layers is not significant, resulting in difficulties in identifying and evaluating hydrocarbon zone and the occurrence of reservoir omission. Based on geological, mud logging, core experimental data, logging, formation water analysis and testing data together, the formation mechanism of low resistivity hydrocarbon zone and the response characteristics of logging curves were generalised. The research suggests that the main factors causing low resistivity in this area are strong heterogeneity, high formation water salinity, high shale content, etc. On this basis, in response to the difficulty of identifying low resistivity gas layers, three methods of assessment were constructed: resistivity reduction rate factor method, porosity curve differentiation technique method and double porosity overlap method, which can quickly identify low resistivity gas layers. The oil testing results have verified that this method significantly improves the interpretation accuracy, with a 17.2% increase in accuracy and good results. The test results show that the method can greatly improve the interpretation accuracy with current accuracy 89.1% and the method turns out to be effective. Based on the above methods, the distribution law of low resistivity oil and gas layers in the study area has been clarified, and favorable zones have been discovered, providing strong technical support for increasing reserves and production in the area.

Geological evaluation of black shale as a suitable Supplementary Cementitious Material (SCM) to optimize the use of clinker in cement production

Faced with challenges like resource depletion and climate change, the cement industry needs sustainable solutions. This study explores the potential of geologically-delinaeated black shale from Apersua, Ghana, as a supplementary cementitious material (SCM) to reduce reliance on traditional methods. The researchers analysed the shale's chemical composition and mineralogy, then created laboratory cement formulations with varying black shale content. These were compared to standard formulations without shale. The results show cement with black shale has comparable compressive strength, meeting standard requirements. Even a formulation with only black shale (excluding limestone, a common ingredient) passed strength tests. Overall, the black shale demonstrated good potential as a SCM based on strength, chemical makeup, setting time, and its possible contribution to durability. This research suggests that black shales from Apersua are worth exploring further as a sustainable and potentially cost-effective alternative in cement production.

Shale Reservoir Rock Physics Modeling and “Sweet Spot” Prediction Based on Digital Core

Abstract With the increasing advancement in shale exploration and development, the complex pore structure and organic-rich characteristics of shale have gradually become the focus of rock physics models. This study combined digital core technology to obtain detailed information on the shale mineral composition, content, pore and crack contents, and composition. The isotropic self-compatible approximation (SCA) model was used to couple the shale minerals and hard pores to construct a brittle mineral framework. The VRH model was used to mix kerogen and clay, and the SCA-DEM (differential equivalent medium) model was used to add organic pores to construct a clay-organic matter mineral framework. The anisotropic SCA model treated the clay-organic matter mineral framework as an inclusion added to the brittle mineral framework to construct the shale mineral framework. The Eshelby–Cheng model was used to add fracture to the mineral framework and establish a physical shale model. This model was used to optimise the selection of sensitive elastic parameters for physical properties such as brittle mineral and kerogen content, fracture density, and porosity, and the optimisation results were combined to construct an explanatory quantity template. In addition, according to actual data from a study area in southwestern China, we combined to the interpretation chart established by the model to perform isotropic inversion. Then, we analyzed and interpreted the brittleness index (BI) and total organic carbon (TOC) content of the reservoir and predicted the sweet spot area of the shale reservoir.

Shale Oil Generation Conditions and Exploration Prospects of the Cretaceous Nenjiang Formation in the Changling Depression, Songliao Basin, China

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part.

Distribution law of Chang 7 Member tight oil in the western Ordos Basin based on geological, logging and numerical simulation techniques

Abstract Fine characterization of oil plane distribution in highly heterogeneous tight sandstone is a prerequisite for efficient reservoir development. This study systematically evaluated the distribution characteristics of tight oil in the Chang 7 Member of the Western Ordos Basin using a large number of experimental tests, logging interpretation, and 3D modelling methods. The logging interpretation models of shale content, porosity, permeability, and oil saturation were constructed, and the effective reservoir was identified by establishing the intersection identification pattern of reservoir acoustic wave time difference and deep lateral resistivity. The 3D numerical simulation results showed that the tight oil is distributed between injection and production wells. The areas with high tight oil content are mainly distributed along the WE direction, and a series of high remaining oil zones are formed locally. Under the influence of long-term injection and production, a high permeability zone will be formed between wells, which is similar to a high-speed channel and will be flooded quickly, and a banded remaining oil retention zone will be formed around it. For the horizontal well flooding area, the water flooding range of the water injection well is small, and a large amount of remaining oil is enriched between water injection wells. Finally, the classification standard of the remaining oil in the Chang 72 sub-member of the study area is proposed, and then, the strategy of adopting different development and adjustment schemes according to different types of reservoirs is formed.

Determination of the Main Production Factors and Production Predictions of Test Wells in the Offshore Tight Oil Reservoirs in the L Formation of the Beibu Basin Using Multivariate Statistical Methods

This study addresses the challenge of rapidly and accurately predicting the production of test wells in offshore tight oil reservoirs, specifically within the L Formation of the Beibu Basin. This challenge is particularly pronounced in situations where drill stem tests are limited and evaluating each untested well layer is difficult. To achieve this objective, we analyzed fifteen typical test wells in the L Formation, taking into account both geological and engineering factors. Initially, Pearson correlation analysis, partial correlation analysis, and grey relational analysis were used to identify the main production factors. Based on these analyses, two types of production prediction models were developed: one employing the comprehensive production index method and the other utilizing the production coefficient method. The research identified effective permeability, porosity, oil saturation, and shale content as the main production factors for the test wells in the study area. The model verification results showed that the comprehensive production index model performs effectively for the L Formation, with an average prediction error of 20.40% compared to the actual production values. This research is significant for optimizing and stabilizing production in tight oil reservoirs.

Three-dimensional reservoir modeling of the pliocene reservoir based on seismic data advances for new prospect assessment

This study presents a comprehensive characterization of the Pliocene reservoir formation in the Temsah gas field, located 65 km NNW of Port Said in the northeastern Nile Delta Basin. The research integrates seismic data with well log analysis to enhance reservoir characterization. The Temsah gas field is distinguished by its intricate geological structure, featuring numerous normal faults oriented along northeast-southwest and northwest-southeast trends. The field’s stratigraphy is predominantly composed of sandstone and shale facies, which are considered highly prospective for hydrocarbon accumulation. A full geological field analysis was conducted to identify key prospects for enhancing productivity. To accurately delineate seismic features, data from four wells and twenty-nine 2D seismic lines were interpreted. Depth maps of the reservoir layers were constructed, highlighting critical transitions between sandstone and shale facies, which are pivotal for future exploration efforts. A detailed 3D static model was developed to illustrate the impact of lithological composition on reservoir characteristics, with a specific focus on the Upper Sand of Kafr El-Sheikh Formation. Petrophysical properties, including effective porosity (13–23%), shale content (7–31%), and water saturation (30–45%), were meticulously evaluated to inform the creation of a robust 3D property model. This model provides a detailed spatial distribution of rock facies and petrophysical parameters within the Temsah gas field. The integration of these studies identified two promising areas, with estimated original gas in place (OGIP) ranging from 2.86 to 4.04 stock cubic feet (SCF), indicating significant potential for field development and enhancement.

Evaluation of gas content in organic-rich shale: A review of the history, current status, and future directions

Shale gas is being hailed as the green energy of the future due to high heating value, low carbon emissions, and large reserves. Gas content of shale is a key parameter for evaluating the shale gas potential and screening for the shale gas sweet spots. Although the concept of gas content has been well defined, obtaining a reliable gas content data still remains a challenge. A significant barrier is the method for evaluating the gas content. In this paper, we provide a review of the long-established and recently developed gas content evaluation methods. In the first part of this review article, the history of gas content evaluation methods is summarized since 1910s, relied on published and unpublished literatures as well as our own experiences. Then, the fundamental contents and concepts involved in gas content evaluation are introduced to provide a clear theoretical foundation for the methods. In the third part, eleven evaluation methods, including four direct methods and seven indirect methods, are systematically reviewed. In each method, its application to evaluating the gas content is presented, the key advances are highlighted, and the advantages and limitations are discussed. Finally, future directions are discussed to promote creative thinking across disciplines to develop new methods or improve current methods for evaluating the gas content more accurately and efficiently.

Evaluation of the Lower Cretaceous Alam El Bueib Sandstone reservoirs in Shushan Basin, Egypt – Implications for tight hydrocarbon reservoir potential

This study presents the evaluation of the potential reservoir intervals in the early Cretaceous Alam El Bueib Formation of the Shushan Basin, Western Desert. Seismic 2D lines, and wireline logs (including image logs) were assessed to characterize the potential intervals. The study area is characterized by E-W to ENE-WSW striking parallel sets of steeply dipping normal faults. Based on the breakouts on image log, the regional maximum horizontal stress orientation is inferred as NE-SW. The AEB Formation, as observed on the image log, consists of massive sandstones, planar laminated siltstones, sandstone-siltstone heteroliths and laminated shales, deposited in a fluvial depositional environment. The bedding planes are WNW-ESE striking with a mean true dip of NNE (around 10°). Wireline log based quantitative petrophysical assessment identified multiple promising hydrocarbon-bearing reservoir intervals within the AEB Formation. The potential reservoir intervals are clean with shale content <10% with water saturation <50%. However, all these intervals are tight with effective porosity between 4 and 12%, dominantly ∼5%. Such tight effective porosity can be contributed by extensive silica cementation in the AEB Formation, as seen from the nearby fields in Western Desert. High porosity zones are observed to be water-bearing. The wells drilled in the north and northeastern area exhibit a cumulative net pay thickness between 70 and 150 ft, while south-southeastern region exhibits a very low cumulative net pay of 10–30 ft. Based on the breakout son image log, the regional minimum horizontal stress orientation is inferred as NW-SE, which can be preferred azimuth for placing highly deviated or horizontal wells to exploit such tight clastic reservoirs by optimizing hydraulic fracture propagation. The formation evaluation presented in this work shed critical insights into the tight hydrocarbon reservoir potential of the early Cretaceous AEB.

An efficient method of predicting S-wave velocity using sparse Gaussian process regression for a tight sandstone reservoir

The shear wave (S-wave) velocity plays a crucial role in interpreting the lithology in seismic data, identifying fluids and predicting reservoirs. However, S-wave velocity is often unavailable due to the high cost of measurement and technical constraints. Conventional methods exhibit limitations that potentially impact the accuracy or efficiency on predicting S-wave velocity. Moreover, these methods always ignore the uncertainty quantification associated with the predicted results. This paper proposes a sparse Gaussian process regression (SGPR) method to predict the S-wave velocity in tight sandstone reservoirs. SGPR is a highly efficient regression technique that is based on the Gaussian process regression (GPR) method. In the SGPR method, inducing inputs are introduced to approximate the kernel matrix to decrease the computational complexity. A sparse set of inducing inputs and kernel hyperparameters are optimized through minimizing the Kullback-Leibler (KL) divergence between the exact posterior distribution and the approximate one. In this study, we select several types of logging data, which include porosity, water saturation, shale content, lithology and P-wave velocity, as the inputs for the SGPR method to predict S-wave velocity. To validate its effectiveness, we use the SGPR method to predict S-wave velocity in tight sandstone and compare the results with those from the GPR method, the bidirectional long short-term memory (BiLSTM) method and the Xu-White model. Additionally, we conduct cross-validation to demonstrate the robustness of the SGPR method. Our findings indicate that the SGPR method presents better performance and significant advantages about the accuracy and efficiency. Moreover, the SGPR method offers uncertainty quantification for the predicted S-wave velocity.

Influence of the sedimentary environment of the Wufeng-Longmaxi shale on organic matter accumulation in the Dingshan area, Sichuan Basin

The sedimentary environment and organic matter (OM) accumulation are vital indicators for shale gas exploration. However, research on deep shale gas systems is relatively limited; moreover, the exploration of deep shale gas in the southeastern Sichuan Basin has entered a period of stagnation. In this study, systematic geochemical analysis of Wufeng (WF) and the first member of the Longmaxi (Long-1) deep shale samples from the recently drilled DY7 well in the Dingshan area of the Sichuan Basin is carried out, and the longitudinal variations in major and trace elements are revealed. The differences in the WF, lower section of the Long-1 (Long-11) and upper section of the Long-1 (Long-12) shales are studied in terms of redox conditions, paleoproductivity, terrigenous detrital input, sedimentation rate and paleoclimate, and the different main controlling factors of OM accumulation for these three layers are discussed. The WF shale has a higher TOC content (mean: 5.73%), the Long-11 shale has a high TOC content (mean: 2.89%), while the Long-12 shale has a low TOC content (mean: 1.44%). For the WF shale, due to complex geological events and large fluctuations in element contents, its TOC content is poorly correlated with these indices, redox and paleoproductivity proxies have a positive association with the Long-11 shale’s TOC content, but negatively correlated with terrigenous input and sedimentation rate indices. The formation of these two sets of organic-rich shales (TOC &amp;gt; 2%) is jointly controlled by good preservation conditions. In contrast, the TOC content of the WF shale is higher than that of the Long-11 shale as the result that terrigenous input and sedimentation rate of the Long-11 shale represent the dilution and destruction of OM, which is different from the former. During the Long-12 depositional period, the water column experienced weak reducing conditions and low productivity, and its high terrigenous debris input further diluted the OM, leading to a low TOC content.

Petrophysical Characteristics of Mauddud Formation in Selected Wells of Ratawi Oilfield, Southern Iraq

The Mauddud Formation is the most widespread Lower Cretaceous formation in Iraq, deposited along the NE margin of the Arabain Palte. The formation is widely distributed, covering nearly the entire territory of Stable and Unstable Shelf units. The study area is located in the Zubair subzone of the Mesopotamian zone within the Stable Shelf unit, approximately 70 km northwest of Basrah in southern Iraq. The main goal of this study is to evaluate the petrophysical characteristics of Mauddud Formation in the five wells (Ratawi-2, Ratawi-4, Ratawi-5, Ratawi-17, and Ratawi-19) in the Ratawi oilfield, southern Iraq. Open hole log analysis was utilized, and a series of calculations were applied to evaluate the reservoir properties, such as porosity, water saturation, and volume shale, that control the reservoir quality. The N-D cross plot diagram shows that limestone is the dominant lithology, and few shale contents is present in the upper and lower parts of the formation, while it is noticed that the volume of clay is constant throughout the formation in most of the wells, indicating that the formation is clean. Seven zones (A to G) have been identified and evaluated, depending mainly on full set logs to determine the most productive ones. Zones B, D, and F are classified as good reservoir zones with an average porosity of 21% and water saturation of 25%. A and C zones show reservoir and non-reservoir zones with porosity of 10% and water saturation of 40%. Finally, the remaining zones represented by E and G are classified as non-reservoir zones with a very low porosity of less than 4% and fully water-saturated.

Prediction of Oil Source Fault-Associated Traps Favorable for Hydrocarbon Migration and Accumulation: A Case Study of the Dazhangtuo Fault in the Northern Qikou Sag of the Bohai Bay Basin

In order to study the distribution pattern of oil and gas near the lower-source, upper-storage type of oil source faults in the hydrocarbon-bearing basins, a set of prediction methods favourable to oil and gas migration and accumulation were established by superimposing the parts of the oil source fault-associated traps, the contiguously distributed sand bodies and the lateral sealing position of faults. The trap associated with a fault can be determined by the fault’s convex part on the fault plane’s morphology map, the fault throw displacement curve and the intersection of faults on the structure map. The set of sand bodies can be determined by the sand-to-shale ration of the formation. The lateral sealing position of faults can be investigated by the shale content of the fault. This study is based on our case study of the Dazhangtuo Fault in the lower sub-member of the 1st member (Es1L) of the Shahejie formation in the northern Qikou Sag of Bohai Bay Basin. The results illustrate 4 fault nose traps formed by fault line deflection in the Es1L formation of the Dazhangtuo Fault, 2 each in the middle and eastern end. The Dazhangtuo Fault is favorable for oil and gas migration except at the eastern and western ends and the middle part of the fault. The fault-associated traps in the Es1L formation that are highly favorable for hydrocarbon migration and accumulation (overlapping site of associated traps and favorable location for oil and gas migration) are distributed in the eastern and central parts of the Dazhangtuo Fault. In contrast, those moderately favorable for hydrocarbon migration and accumulation (associated trap at a certain distance from the favorable location for oil and gas migration in the Dazhangtuo Fracture) are locally distributed in the east. Both traps are conducive to accumulating hydrocarbons from the underlying source rock in the Es3 formation. Such observations are consistent with the current confirmed hydrocarbon distribution, thus validating the feasibility and accuracy of predicting the distribution of traps related to oil source faults favorable for hydrocarbon migration and accumulation, it can be used to guide the exploration of the lower-source, upper-storage type of hydrocarbon accumulations in the hydrocarbon-bearing basins.

Prediction of tight sandstone reservoirs by multiwave joint prestack inversion technology: A case study of the Qiulin area in the Sichuan Basin

The Shaximiao (SXM) Formation of the Middle Triassic in the central Sichuan Basin is a river-lake sedimentary system with an average burial depth of 2800 m. The channel sand bodies of the SXM Formation in the Qiulin area are developed with large lateral variation and high- and medium-porosity sand. This leads to great differences in the seismic response and difficulty in predicting the sand bodies and reservoirs using P-wave data. We carry out well-log analysis for different types of sand bodies. The no. 8 sand body of high porosity can be effectively identified using P-wave impedance (PI). Whereas for the no. 7 sand body of relatively lower porosity (mainly due to the higher shale content in the no. 7 sand compared with the no. 8 sand), sandstone and mudstone can be distinguished using S-wave impedance (SI), and reservoirs can be recognized by the P- to S-wave velocity ratio ([Formula: see text]/[Formula: see text]). Based on the PP wave and the P-to-S converted wave (PS wave) (after matching) angle-stacked data, a prestack inversion of multicomponent data is performed. Multiwave joint inversion results (SI and [Formula: see text]/[Formula: see text]) have better accuracy and stronger stability than the PP-wave inversion in practical application. In addition, the PI of the joint inversion more clearly describes the distribution and boundaries of the channel sand and better matches the prediction and drilling data in sand 8. The SI of the joint inversion can identify subtle sand bodies (weak PI contrast) that are difficult to be detected by PP-wave inversion. The distribution of the reservoir predicted by the [Formula: see text]/[Formula: see text] of the joint inversion is clearer (the no. 7 sand body) and better than that by the PP-wave inversion. This study demonstrates the advantage of the multiwave joint inversion technology in tight sand identification.

Petrophysical Evaluation of Arkoses Reservoirs Based on Well Logs and Plug Samples: A Case Study From Alagamar Formation, Southeastern Portion of Onshore Potiguar Basin, Brazil

The Potiguar Basin is a sedimentary basin located in northeastern Brazil. It covers about 48,000 km² and extends from onshore to offshore. The onshore basin is thought to have formed during the Late Cretaceous, as a result of the opening of the Equatorial South Atlantic Ocean, filled with a thick sequence of sedimentary rocks, including sandstones, shales, and limestones, which were deposited in a variety of processes, including marine, deltaic, and fluvial. The study area is in the southern portion of the basin and the reservoir is composed of arkose sandstones deposited by alluvial fan and fluvial systems of the Upanema Member of the Alagamar Formation, which belongs to the post-rift phase of the Potiguar Basin. Recently, new drilling campaigns revealed a reservoir heterogeneity in these deposits, which requested a new petrophysical approach. Using conventional well logs and petrophysical laboratory analysis of plug samples, this study evaluated the best way to calculate the effective porosity, and shale volume and to understand the stratigraphic controls in the distribution of these properties. Three reservoir zones were mapped: the basal one, Zone 3, has disconnected sand bodies, low porosity, and high shale content; Zone 2 has better petrophysical properties, lateral distribution, and connectivity between the fans and Zone 1 is the better reservoir zone with larger sand bodies, higher porosity values, and well-connected fans.

The development and utilization of shale oil and gas resources in China and economic analysis of energy security under the background of global energy crisis

The key scientific problem to be solved in this paper is the optimal development and utilization model and the economic evaluation model of China's land-phase shale oil and gas resources, and the purpose of the research is to promote the large-scale commercial development and utilization of China's shale oil and gas resources, and to safeguard China's oil and gas energy security and the sustainable development of the economy. The article proposes to adopt the small surface element volume method (oil content rate method) to evaluate the pure shale oil resources, adopt the Cobb–Douglas production function model as the optimization model to measure the boundary production capacity of shale oil and gas, construct the optimal development and utilization model for shale oil and gas resources considering the five first-level safeguard indexes, namely, science and technology (A), capital (K), talents (L), reserves (S) and ecological environment (E), and establish the basic constraint model for the optimal development and utilization of shale oil and gas resources. The basic constraint model, as well as the evaluation model of economic coefficients for the development and utilization of shale oil and gas resources were established. The pure shale oil resources are mainly calculated based on the movable oil content of shale. In the paper, the S1 of normal pyrolysis (300 °C) is regarded as movable oil, and the sum of S1 and evaporated hydrocarbon (light hydrocarbon) loss is the movable oil content of shale. The integrated geological-physical exploration-engineering comprehensive evaluation of China’s land-phase shale oil-rich and high-yielding “sweet spot” is an important prerequisite for the realization of shale oil and gas resources to build production scale and effective development, and the least-squares method is used to estimate the average production function, the distance to the maximum value of the residuals, and the boundary capacity production function. The average production function and residual maximum distance are estimated by the least squares method, and the production function of the boundary capacity is derived, and the quotient of the boundary capacity and the actual capacity is calculated to get the capacity utilization rate, which can be used to analyze the potential of future shale oil and gas growth. The development of shale oil and gas resources in a target block requires comprehensive consideration of the first-level guarantee indicators such as science and technology (A), capital (K), talents (L), reserves (S) and ecological environment (E), as well as more than 10 s-level indicators and a number of third-level indicators, in order to ensure that the oil companies maximize their profits by organizing the development and production. The economic coefficient can be expressed as the ratio of economically recoverable resources to geological reserves. The larger the economic coefficient for the development and utilization of shale oil and gas resources is, the better the economy of the area is, and the larger the proportion of shale oil and gas resources that can be exploited. There is little special literature on the optimal development and utilization model of shale oil and gas resources and energy security among many research results at home and abroad. The evaluation of pure shale oil using the small surface element volume method (oil content rate method) and the construction of the boundary capacity calculation model, the optimal development of the basic constraints model and the economic evaluation model that we have determined, although they can not yet fully cover all the links and factors related to the development and utilization of shale oil and gas resources, are not yet fully covered by our research work. However, our research work has given the model more geological and economic theoretical connotations, and provided an economic basis and technical reference for the large-scale and commercial development and utilization of shale oil and gas resources as an effective alternative to oil imports.