Exploration Of Gas Reservoirs Research Articles

Prediction Technology of a Reservoir Development Model While Drilling Based on Machine Learning and Its Application

In order to further understand the complex spatial distribution caused by the extremely strong heterogeneity of buried hill reservoirs, this paper proposes a new method for predicting the development pattern of buried hill reservoirs based on the traditional pre-drilling prediction and post-drilling evaluation methods that mainly rely on seismic, logging, and core data, which are difficult to meet the timeliness and accuracy of drilling operations. Firstly, the box method and normalization formula are used to process and normalize the abnormal data of element logging and engineering logging, and then the stepwise regression analysis method is used to optimize the sensitive parameters of element logging and engineering logging. The Light Gradient Boosting Machine (LightGBM) algorithm, deep neural network (DNN), and support vector machine (SVM) are used to establish a new method for predicting the development pattern of buried hill reservoirs. Lastly, a comprehensive evaluation index F1 score for the model is established to evaluate the prediction model for the development pattern of buried hill reservoirs. The F1 score value obtained from this model’s comprehensive evaluation index indicates that the LightGBM model achieves the highest accuracy, with 96.7% accuracy in identifying weathered zones and 95.8% accuracy in identifying interior zones. The practical application demonstrates that this method can rapidly and accurately predict the development mode of buried hill reservoirs while providing a new approach for efficient on-site exploration and decision-making in oil and gas field developments. Consequently, it effectively promotes exploration activities as well as enhances the overall process of oil and gas reservoir exploration.

Tight carbonate reservoir evaluation case study based on neural network assisted fracture identification and analytic hierarchy process

AbstractComprehensive evaluation of reservoirs is an important link in gas reservoir exploration and development. The evaluation of tight carbonate reservoirs often focuses on the characteristics of porosity and permeability, ignoring the important factor of fractures, also the quantitative evaluation of reservoirs is relatively few. It is difficult to identify fractures and evaluate the reservoir factors qualitatively and quantitatively. Herein, the sedimentary microfacies and microporosity of the tight carbonate reservoir of the Ma55 submember in the eastern Sulige area are comprehensively studied by casting thin section, rock physical property, and capillary pressure test data. The backpropagation (BP) neural network algorithm is used to identify and predict fractures. Finally, through the analytic hierarchy process, the above reservoir influencing factors are modeled and quantitatively analyzed for reservoir evaluation. The results show that the highest probability of fracture development in the central and northwest areas of the study area can reach 0.92. The accuracy of the BP neural network model in identifying cracks can reach 80%, which is reliable and effective compared with the conventional logging identification method. Reservoirs can be classified into four types according to their quality. The synthetic weights of porosity, permeability and fracture development probability are 0.2, 0.2 and 0.216 respectively, which are the three most important evaluation parameters. This study improves the accuracy of fracture identification and prediction of tight reservoirs in comprehensive reservoir evaluation, which provides guidance and scheme for more detailed exploration and development of tight carbonate reservoirs.

Evaluation of Aminated Nano-Silica as a Novel Shale Stabilizer to Improve Wellbore Stability.

The issue of wellbore instability poses a significant challenge in the current exploration of shale gas reservoirs. Exploring more efficient shale stabilizers has always been a common goal pursued by researchers. In this paper, a novel shale stabilizer, denoted as ANS, was prepared by employing a silane-coupling modification method to graft (3-Aminopropyl) triethoxysilane (APTES) onto the surface of nano-silica. The structure of ANS was characterized through Fourier transforms infrared spectroscopy (FT-IR), thermo-gravimetric analysis (TGA), and particle size tests (PST). The shale stabilizing properties of ANS were evaluated through tests such as pressure penetration, BET analysis, hydration expansion and dispersion. Furthermore, the interaction between ANS as a shale stabilizer and clay was explored through clay zeta potential and particle size analysis. The results indicated that ANS exhibited a stronger plugging capability compared to nano-silica, as evidenced by its ability to increase the shale pressure penetration time from 19 to 131 min. Moreover, ANS demonstrated superior hydration inhibition compared to commonly used KCl. Specifically, it reduced the expansion height of bentonite from 8.04 to 3.13 mm and increased the shale recovery rate from 32.84% to 87.22%. Consequently, ANS played a dual role in providing dense plugging and effective hydration inhibition, contributing significantly to the enhancement of wellbore stability in drilling operations. Overall, ANS proved to be a promising shale stabilizer and could be effective for drilling troublesome shales.

Reservoir Characteristics and Formation Model of the Bauxite Gas Reservoir: The Benxi Formation in the LX Block, Northeast of Ordos Basin, China.

Recently, horizontal well L47-1CH in the Longdong area of the southwestern Ordos Basin made a significant breakthrough in bauxite natural gas exploration, changing the traditional geological understanding that bauxite could not form effective reservoirs. To further explore the exploration and development potential of bauxite natural gas reservoirs in the northeast of the Ordos Basin, it is urgent to carry out basic geological studies. This paper discusses the sedimentary environment, reservoir characteristics, and formation patterns of the bauxite gas reservoirs in the LX Block using trace elements, thin sections, X-ray diffraction, scanning electron microscopy, conventional physical properties, constant pressure mercury, etc. Then, the distribution pattern of bauxite was studied according to the restoration of the karst paleogeomorphology, and the formation model of bauxite was ultimately established. The results show that bauxite developed a clear triple-segment structure vertically, characterized by rich iron at the bottom, high aluminum at the middle, and low iron at the top. The mineral composition of the bauxite section mainly includes diaspore, iron minerals, titanium minerals, and birnessite. The types of pores mainly include intra- and intergranular dissolved pores, matrix-dissolved pores, intercrystalline pores, and microfractures. The porosity ranges from 1.51 to 9.90%, with a relatively good sorting and connectivity of the pore and throat. The bauxite was formed in a hot and humid climate, deposited in a shallow-water tidal flat and lagoon sedimentary environment with oxygen depleted, and experienced oscillatory regression during the deposition process. The thickness of bauxite is significantly controlled by karst paleogeomorphology, and it is mainly distributed at the negative terrain positions of karat pits and karst terraces. The above results can provide a geological basis for the exploration and development of bauxite in the Ordos Basin and similar basins worldwide.

Acylated Inulin as a Potential Shale Hydration Inhibitor in Water Based Drilling Fluids for Wellbore Stabilization.

Shale hydration dispersion and swelling are primary causes of wellbore instability in oil and gas reservoir exploration. In this study, inulin, a fructo-oligosaccharide extracted from Jerusalem artichoke roots, was modified by acylation with three acyl chlorides, and the products (C10-, C12-, and C14-inulin) were investigated for their use as novel shale hydration inhibitors. The inhibition properties were evaluated through the shale cuttings hot-rolling dispersion test, the sodium-based bentonite hydration test, and capillary suction. The three acylated inulins exhibited superb hydration-inhibiting performance at low concentrations, compared to the commonly used inhibitors of KCl and poly (ester amine). An inhibition mechanism was proposed based on surface tension measurements, contact angle measurements, Fourier-transform infrared analysis, and scanning electron microscopy. The acylated inulin reduced the water surface tension significantly, thus, retarding the invasion of water into the shale formation. Then, the acylated inulin was adsorbed onto the shale surface by hydrogen bonding to form a compact, sealed, hydrophobic membrane. Furthermore, the acylated inulins are non-toxic and biodegradable, which meet the increasingly stringent environmental regulations in this field. This method might provide a new avenue for developing high-performance and ecofriendly shale hydration inhibitors.

Utilization method of low-grade thermal energy during drilling based on insulated Drill pipe

Downhole heat damage during drilling seriously restricts the exploration and development of deep oil and gas reservoirs and geothermal resources. The petroleum industry focuses on controlling the downhole heat damage during drilling while utilizing low-grade thermal energy and making it profitable. Therefore, a techno-economic coupling evaluation model is developed for a low-grade thermal energy utilization system developed for use during drilling along with a wellbore heat transfer model. Subsequently, based on the model, the influence of different lengths and installation positions of insulated drill pipe (IDP) on the downhole temperature is studied. Then, on the premise of satisfying the wellbore cooling target, the system is economically evaluated based on factors such as production time, government subsidy, and electricity price, and the corresponding measures are proposed to make the system profitable. Finally, a set of efficient IDP-based low-grade thermal energy utilization methods is developed. The case study presented herein shows that the IDP length that allows the system to reach the maximum profit in the 10th year is 4720 m for a horizontal well with a depth of 6200 m when the government one-off subsidy rate is 30% and electricity price is increased by 30%.

Sedimentary characteristics and model of seasonal deltaic sandstone: a case study on the continental red bed from the Cretaceous Baxigai Formation, Tarim Basin, NW China

Seasonal delta is a sandy fan-shaped sedimentary system formed by seasonal river flooding in continental basins. Modern sedimentary finds that seasonal deltas mainly develop in an arid-semi-arid climate environment with gentle terrain. However, the study of seasonal deltas in ancient rock records is still insufficient, leading to misinterpretations as other sedimentary systems, which poses challenges to the correct understanding of the origin and spatial distribution of sand body deposits. In this study, the red bed deposits of the Cretaceous Baxigai Formation in the west of the Tabei Uplift were selected as the research object. Based on core observation and description, a comprehensive analysis of the sedimentary environment, sedimentary characteristics and sedimentary model of the Baxigai Formation was carried out using data such as well-logging and analytical testing, combined with modern depositional characteristics. Research shows that the sedimentary sequence of the Baxigai Formation red bed developed a seasonal delta sedimentary system in the arid climate. The seasonal delta deposits provide an opportunity to understand the influencing of river flow and total sedimentary loading vary greatly on the sedimentary model, sedimentary mechanism, and distribution of sand bodies in arid climates. The sedimentary process of the seasonal delta in the Baxigai Formation was controlled by the dual-stage sedimentation process in an arid paleoclimate. During the flood period, the supercritical flow sedimentary structures are widely developed in the major distributary channels, and the distributary channels migrate and bifurcate frequently. On the delta plain, crevasse channels are formed through the avulsion of major distributary channels. During the dry period, due to the consumption of water seepage and evaporation transfer, terminal distributary channels are abandoned, crevasse channels are not developed, and the sediment is exposed. The density of the distributary channels is reduced, and the total sedimentary loading is low. The distributary channels sand body is the skeleton sand body of the seasonal delta. This study is of great significance for accurately explaining the formation process of seasonal deltas and provides a useful reference for further exploration and deployment of oil and gas reservoirs and paleogeographic reconstruction in the study area.

Reservoir parameters prediction based on spatially transferred long short-term memory network.

Reservoir reconstruction, where parameter prediction plays a key role, constitutes an extremely important part in oil and gas reservoir exploration. With the mature development of artificial intelligence, parameter prediction methods are gradually shifting from previous petrophysical models to deep learning models, which bring about obvious improvements in terms of accuracy and efficiency. However, it is difficult to achieve large amount of data acquisition required for deep learning due to the cost of detection, technical difficulties, and the limitations of complex geological parameters. To address the data shortage problem, a transfer learning prediction model based on long short-term memory neural networks has been proposed, and the model structure has been determined by parameter search and optimization methods in this paper. The proposed approach transfers knowledge from historical data to enhance new well prediction by sharing some parameters in the neural network structure. Moreover, the practicality and effectiveness of this method was tested by comparison based on two block datasets. The results showed that this method could significantly improve the prediction accuracy of the reservoir parameters in the event of data shortage.

Characteristics of Tight Gas Reservoirs in the Xujiahe Formation in the Western Sichuan Depression: A Systematic Review

In current energy structure adjustments, the prominence of unconventional oil and gas resources continues to grow, with increasing attention being paid to tight gas, a major component of natural gas production. The Xujiahe Formation gas reservoir in the Western Sichuan Depression represents a typical tight gas reservoir and the study of its reservoir characteristics is a key focus for current and future exploration and development efforts. This review employs the PRISMA method to screen and integrate the primary findings of 26 documents spanning the period from 2008 to 2023, with the aim of providing a comprehensive overview of the progress and outcomes of research on the tight gas reservoir characteristics of the Xujiahe Formation in the Western Sichuan Depression. The selected research documents summarize the characteristics of the Xujiahe Formation tight gas reservoir in the Western Sichuan Depression from four perspectives: lithology, physical properties, reservoir space, and the main factors influencing reservoir quality. Through a review of these previous studies, it is evident that existing research has predominantly focused on the relationship between diagenesis and reservoir densification, indicating certain limitations. We also delve into the characteristics of tight gas sandstone reservoirs in the study area, considering their depositional systems, fracture development, cementation, and impact on the exploration and development of tight gas reservoirs. Additionally, we propose measures to stabilize and enhance tight gas production in the Xujiahe Formation in the Western Sichuan Depression. Moreover, we outline the next steps for further research and exploration.

Research on geophysical response analysis and prediction technology of geostress in the shale gas area of the southern Sichuan Basin

The exploration and development potential of shale gas reservoirs in the Sichuan Basin is enormous; however, it also faces difficulties such as complex structures, strong heterogeneity, and unclear geophysical response characteristics. Fine prediction of geostress is an important part of shale gas exploration and development, which directly affects the implementation effect of reservoir evaluation, well trajectory design, and fracture reconstruction. The existing geostress prediction techniques lack high-precision seismic data constraints, making it difficult to accurately reflect the planar distribution characteristics of geostress in the block with rapid changes in complex tectonic zones. At the same time, the geophysical response characteristics of geostress in the Sichuan Basin are unknown, and the geostress seismic prediction technology lacks theoretical basis. This paper combines numerical simulation and physical experiments and defines the characteristics of the geophysical response of shale gas reservoirs in the Sichuan Basin changing with the stress field, and technical countermeasures for geostress seismic prediction have been established to provide technical means for accurate prediction of the geostress field in the shale gas block. Based on the geostress sensitive parameters obtained from prestack seismic inversion, the geostress field prediction of a shale gas work area in the Sichuan Basin is realized.

The geological controlling factors of the heterogeneity of a bioclastic limestone reservoir—a case study of the Cretaceous Kh2 layer in A oilfield, Iraq

Reservoir heterogeneity is one of the key factors affecting the exploration and development of oil and gas reservoirs. The Kh2 layer in the A field of Central Iraq is a major pay zone with strong longitudinal and lateral heterogeneity. The heterogeneity, controlled by geological factors, has not yet been confirmed, which seriously restricts the development of this pay zone. This study aims to establish a geological pattern for the reservoir heterogeneity of bioclastic limestone, providing a geological basis for heterogeneity evaluation. Based on the core observation, thin-section identification, and physical property analysis, the microfacies are classified, and the diagenetic sequences and the pore structure of the Kh2 layer are analyzed. Seven types of microfacies are developed in the Kh2 layer, namely, planktic foraminiferal wackestone (MFT1), lamellar bioclastic wackestone (MFT2), intraclastic–bioclastic packstone (MFT3), green algal packstone (MFT4), green alga–pelletoid packstone (MFT5), bioclastic–intraclastic packstone (MFT6), and intraclastic grainstone (MFT7). The heterogeneity of the different microfacies and heterogeneity within the same microfacies were evaluated using the variation coefficient of permeability tested from cores collected from wells and calculated by well-logging at different intervals. The highest heterogeneity was observed in the lamellar bioclastic wackestone (MFT2), with an average variation coefficient of 0.72. The lowest heterogeneity was observed in the green algal packstone (MFT4), with an average variation coefficient of 0.11. The vertical heterogeneity of the permeability is mainly controlled by sedimentation, while the lateral heterogeneity is mainly influenced by cementation, bioturbation, and the distribution of green algae. Finally, a micro-scale geological pattern for determining the reservoir heterogeneity of bioclastic limestone reservoirs is established. This study can guide the current injection development and remaining oil prediction in oilfields with similar backgrounds.

Tectonic movements of the Yanshan-Himalayan period in the northern Longmenshan and their impact on tight gas accumulation of the Shaximiao formation in the Qiulin structure, China

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin’s formation is influenced by gravitational gliding tectonics, which can be classified into the ‘Three Zones and One Belt,’ with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin.

Multivariable Regression 3D Failure Criteria for In-Situ Rock

Wellbore stability problems increase with the exploration and development of oil and gas reservoirs. A new 3D non-linear failure criterion is proposed as a trigonometric function considering the intermediate principal stress (2) on the triaxial compression test data. Mohr-Coulomb and Hoek-Brown are well-known failure criteria, but they do not consider the influence of (2) on rock strength. This new criterion produces a concave surface on the principal stress space (1,2, 3) with the influence of intermediate principal stress. In this study, sensitivity analysis for the variable is also done to understand the significant influence of parameters on the accuracy of the proposed criterion. Further validation of this non-linear criterion on three principal stresses (1,2, 3) was done compared with linear regression and second-degree polynomial regression results. It has been observed that the new non-linear 3D criterion with five material parameters reveals a good fit compared to linear regression and second-degree polynomial regression, which have four and six material parameters, respectively. The new non-linear criterion was further validated by comparison with existing criteria like the Priest, Drucker-Prager, and Mogi-Coulomb. It has been observed that the new 3D non-linear criterion shows a more accurate result than these existing criteria as certain rock types exhibit coefficient of determination (DC) values near one, precisely 0.95 for inada granite, 0.94 for orikabe monzonite, and 0.91 for KTB amphibolite. In contrast, other rock types have DC values ranging from 0.7 to 0.9. The new 3D non-linear criterion also yields lower root means square error (RMSE) values than the Mogi-Coulomb criterion for seven rock types. Specifically, the RMSE values by the new criterion are as follows: KTB amphibolite - 40.03 MPa, Dunham dolomite - 15.16 MPa, Shirahama sandstone - 9.08 MPa, Manazuru andesite - 22.14 MPa, Inada granite - 35.47 MPa, and Coconino sandstone - 19.047 MPa. This new 3D criterion gave precise predictions of the failure of the formation under in-situ stresses and was further helpful for the simulation of the wellbore in the petroleum industry. The variable in the new 3D criterion should be calculated from triaxial compression test data for each formation rock before applying this criterion to the wellbore stability problem and the sand production problem.

An innovative fracture plugging evaluation method for drill-in fluid loss control and formation damage prevention in deep fractured tight reservoirs

Lost circulation, resulting from the undesired loss of drilling fluid into formation fractures, stands as a significant technical obstacle in the exploration and production of oil, gas, and geothermal reservoirs. Effective mitigation of this challenge requires the development and application of robust experimental evaluation methods to assess the effectiveness of fracture plugging. The traditional approach to fracture plugging evaluation relies on a uniform evaluation index and experimental parameters for various lost circulation types. Unfortunately, this practice frequently results in inconsistent performance of loss control formulas during laboratory experiments and field tests. To address this issue, this paper introduces an innovative evaluation method that accounts for the specific characteristics of the three major lost circulation types. By adopting this approach, a more scientifically rigorous design and optimization of loss control formulas can be achieved, ensuring their effectiveness in managing lost circulation challenges. The development of the new method involves a systematic five-step establishment process: lost circulation type determination, evaluation index weight calculation, fitness degree analysis between laboratory experiment and field test, experimental parameters optimization, and quantitative scoring of loss control formula. Analytic hierarchy process is adopted to calculate the evaluation index weight. Quantitative scoring model is proposed to finally determine the integrated formula score for the quantitative evaluation and scientific optimization of loss control formula. To bridge the gap between laboratory and field applications, laboratory evaluation tests are developed to address different types of lost circulation scenarios. The experimental results demonstrate significant improvements achieved through the optimized formula. Specifically, the maximum plugging pressure increased from 5 MPa to 20.8 MPa, while the initial and cumulative loss volumes witnessed reductions of 30.3 ml and 121.2 ml, respectively. Moreover, the evaluation method proposed in this paper exhibits a fitting degree of over 90 % when compared to the actual control effect on drilling fluid loss. These findings substantiate the successful establishment of a connection between laboratory evaluations and field performance, providing valuable insights for future applications. Finally, a novel evaluation method for assessing the fracture plugging effect is established, accounting for various lost circulation types in deep fractured tight reservoirs. The reliability of this proposed evaluation method is validated by field test. Building upon this method, a high-score formula is designed and effectively deployed in a deep fractured tight reservoir in Tarim Basin, China. The successful application highlights the practical value and robustness of the developed evaluation method, offering promising prospects for future operations in similar reservoir settings.

Reservoir characteristics and controlling factor of tight sandstone in Shuixigou Group in Taibei depression, Turpan-Hami basin

The positive structure belts surrounding the Taibei Sag, Turpan-Hami Basin, have been the main targets for oil and gas exploration for years and are now left with remaining resources scattering in reservoirs adjacent to source rocks in the sag, where the Shuixigou Group with substantial oil and gas potential constitutes the primary focus for near-source exploration. Consequently, characterization of development and key controlling factors of reservoir space becomes a must for future exploration in the area. This study investigates the development traits, genesis, and controlling factors of the Xishanyao and Sangonghe formations in the Shengbei and Qiudong Sub-sags of the Taibei Sag with techniques such as cast thin-section observation, porosity and permeability tests, high-pressure mercury injection, and saturation fluid NMR analysis of reservoir rocks. The findings reveal that the Shuixigou Group in the Taibei Sag consists of lithic sandstone. Reservoirs in the group are mostly poor in terms of physical properties, with undeveloped primary pores dominated by intergranular dissolved pores as a result of a strong compaction. Comparative analysis of key controlling factors of the Sangonghe Formation reveals significant distinctions in sandstone particle size, sand body thickness, genesis and distribution, provenance location, and source rock type between the Qiudong area and Shengbei area. Vertically, the coal seams of the Xishanyao Formation exhibit heightened development with shallower burial depth and lower maturity compared to those of the Sangonghe Formation. Consequently, this environment fosters the formation of organic acids, which have a stronger dissolution effect on minerals to develop secondary dissolution pores, and ultimately resulting in better reservoir physical properties. Overall, the reservoirs within the Qiudong area of the Taibei Sag demonstrate superior characteristics compared to those in the Shengbei area. Furthermore, the reservoir physical properties of the Xishanyao Formation are better than those of the Sangonghe Formation. The research findings will provide valuable guidance for the exploration and development of lithological oil and gas reservoirs within the Taibei Sag.

Significant Influence of Sand Production on the Well's Drainage Area

The exploration of unconventional oil and gas reservoirs is a prominent global trend today. Achieving cost-effective and efficient hydrocarbon production from these reservoirs necessitates advanced technologies. One such technology that has been employed in the oil and gas industry for many decades is hydraulic fracturing. It is used to create highly conductive channels within formations characterized by extremely low permeability values. The successful implementation of hydraulic fracturing hinges on the development of an effective fracturing design. This design is crucial to achieving the anticipated production outcomes from unconventional reservoirs, including tight gas, shale gas, coal bed methane, and reservoirs with very low permeability. Key parameters for the success of hydraulic fracturing operations include the determination of the optimal fracturing rate, fracture height, and the selection of propping agents. These factors collectively contribute to the efficiency and productivity of hydraulic fracturing activities in unconventional reservoirs.

Quantitative inversion of the elastic parameters outside the borehole based on exact Zoeppritz equations

The acoustic remote detecting method in the borehole has developed rapidly in the past few decades. It uses the reflected waves recorded by array receivers based on monopole or dipole sources in the fluid filled borehole to image geological structures outside the well. The result can provide guidance on the exploration and evaluation of oil and gas reservoirs and mineral resources. However, the present structure imaging results lack of the elastic information, which limit the quantitative evaluation of the resources. The AVO (amplitude variation with offset) inversion theory is introduced into the analysis of borehole waves. The interested interfaces (fractures or minor faults) with a generally larger wave impedance difference makes the widely used approximate equation in the surface exploration no longer applicable. Therefore, the exact Zoeppritz equations are used as the forward equations in the inversion. To reduce the nonlinearity of inversion, the initial model combining structure tensor and mode wave velocity analysis is constructed. The simultaneous inversion of the wave velocity and density of the reflector provides a theoretical basis for quantitatively evaluating the elastic parameters of the reservoir outside the borehole. [Work supported by the National Natural Science Foundation of China (42004117 and 42127807).]

A data-driven method for total organic carbon prediction based on random forests

The total organic carbon (TOC) is an important parameter for shale gas reservoir exploration. Currently, predicting TOC using seismic elastic properties is challenging and of great uncertainty. The inverse relationship, which acts as a bridge between TOC and elastic properties, is required to be established correctly. Machine learning especially for Random Forests (RF) provides a new potential. The RF-based supervised method is limited in the prediction of TOC because it requires large amounts of feature variables and is very onerous and experience-dependent to derive effective feature variables from real seismic data. To address this issue, we propose to use the extended elastic impedance to automatically generate 222 extended elastic properties as the feature variables for RF predictor training. In addition, the synthetic minority oversampling technique is used to overcome the problem of RF training with imbalanced samples. With the help of variable importance measures, the feature variables that are important for TOC prediction can be preferentially selected and the redundancy of the input data can be reduced. The RF predictor is finally trained well for TOC prediction. The method is applied to a real dataset acquired over a shale gas study area located in southwest China. Examples illustrate the role of extended variables on improving TOC prediction and increasing the generalization of RF in prediction of other petrophysical properties.

Time-Lapse 3D CSEM for Reservoir Monitoring Based on Rock Physics Simulation of the Wisting Oil Field Offshore Norway.

The marine controlled-source electromagnetic (CSEM) method has been used in different applications, such as oil and gas reservoir exploration, groundwater investigation, seawater intrusion studies and deep-sea mineral exploration. Recently, the utilization of the marine CSEM method has shifted from petroleum exploration to active monitoring due to increased environmental concerns related to hydrocarbon production. In this study, we utilize the various dynamic reservoir properties available through reservoir simulation of the Wisting field in the Norwegian part of the Barents Sea. In detail, we first developed geologically consistent rock physics models corresponding to reservoirs at different production phases, and then transformed them into resistivity models. The constructed resistivity models pertaining to different production phases can be used as input models for a finite difference time domain (FDTD) forward modeling workflow to simulate EM responses. This synthetic CSEM data can be studied and analyzed in the light of production-induced changes in the reservoir at different production phases. Our results demonstrate the ability of CSEM data to detect and capture production-induced changes in the fluid content of a producing hydrocarbon reservoir. The anomalous CSEM responses correlating to the reservoir resistivity change increase with the advance of the production phase, and a similar result is shown in anomalous transverse resistance (ATR) maps derived from the constructed resistivity models. Moreover, the responses at 30 Hz with a 3000 m offset resulted in the most pronounced anomalies at the Wisting reservoir. Hence, the method can effectively be used for production-monitoring purposes.

Investigation into a perfect matching between fracture transfer performance and vertical well productivity based on multi-scale and total factor characteristic models

In fractured tight gas reservoirs, complex hydraulically induced fracture networks determine fluid flowing abilities of reservoirs. Thus, characterizing the complex fracture networks and revealing fracture transfer performances become a challenging work because of fracture branching, bending, and reversing in fractured reservoirs. In this paper, a fractal-like tree-shaped fracture model for gas transfer is proposed to optimize flow conductivity, pressure distribution at fracture intersection points, and flow transfer in such a complex fracture network considering the multi-scale effect, and total factor characteristics, including the length ratio, width ratio, branching angle, and branching level. The model is implemented to conduct validation against the experiment data in the literature. Subsequently, applying the proposed fracture model, the productivity equation for a vertical gas well intercepted by the fractal-like tree-shaped fracture network is further formulated. In addition, the good match with productivity simulation validates the accuracy of the developed productivity model for a vertical gas well. As a result, the impacts of the Knudsen number, fracture total factor characteristics, reservoir parameters, etc. on fracture transfer performances and well productivity are examined using the two proposed models. The results demonstrate that optimum fracture transfer performances do not match with the maximum well productivity. In contrast, the well productivity is jointly determined by both inlet flow volume of the fracture network and matrix permeability. Hence, a new formula considering both fracture characteristics and reservoir properties is proposed to match with the optimum fracture total length and maximum well productivity, thereby contributing to high-efficient and economic exploration of tight gas reservoirs.