Unconventional Resources最新文献

Identifying fractures is important for optimizing recovery and enhancing oil recovery techniques. Identifying natural fractures using FMI and cores is expensive and unavailable for all wells. Therefore, predictive models based on conventional wireline logs are necessary. Extreme Gradient Boosting, Decision tree, Random Forest, Support Vector Machine, Feed Forward Neural Network, and Recurrent Neural Network were applied to identify natural fractures. This study uses well logs to develop a new Fracture Signature Function equation for determining natural fractures in the shale reservoir. This unsupervised approach requires no special image log to identify natural fractures. However, the class imbalance problem between the fracture and non-fractured zone often restricts the accuracy of the machine learning models, which require a predictive model not dependent upon the special logs and class imbalance problems in the prediction of fractured zones. Synthetic Minority Oversampling (SMOTE) and Random Oversampling (ROS) were applied to solve the class imbalance problem in the data. The results show that the machine learning models did not predict the fracture and non-fracture zones with acceptable accuracy even after applying SMOTE and ROS. Relative to all machine learning models, Random Forest predicted the results with the highest accuracy of 91 % and F1-Score of 17.6 %. The Fracture Signature Function (FSFn'') predicted the natural fractures with high accuracy except in zones with very complex borehole environments. A Forward Neural Network is more efficient in identifying fracture and non-fractured zones in imbalance class problems of the dataset. The Recurrent Neural Network's predictions were biased toward the major class related to the non-fractured zone of the studied interval. The newly developed equation can be used for natural fracture identification in drilling and production strategy design by using the easily available well-log data in class imbalanced conditions.

Mixed depositional reservoirs are widely distributed in Junggar Basin, NW China. These reservoirs are featured by complex lithology, ultra-low permeability and extremely heterogeneous pore structures that markedly impact field development efficiency. This study illustrated the distribution of lithological combinations within a single sand bar in the Middle Permian Lucaogou Formation, Jimsar Sag, Junggar Basin and revealed the diagenetic control on the reservoir quality of a single sand bar based on thin sections, scanning electron microscopy (SEM), helium porosity and air permeability measurement, pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), X-ray computed tomography (CT), and collected and published data. The results show that the heterogeneity of microscopic pore structures within a single sandbar is controlled by the distribution of various lithological combinations and different levels of diagenetic alteration. The results show that there are mainly three types of lithology developed in a single sand bar. The reservoir quality of dolomitic siltstone reservoirs is the best, followed by silty dolomite reservoirs. The reservoirs quality of dolomicrite reservoirs is the worst. Three main lithological combinations can be identified within a single sand bar. Controlled by climate, lake level fluctuation and provenance, lithological combination A, characterized by blended mixing of dolomitic siltstone, silty dolomite and dolomicrite, is mainly developed in the middle of single sand bar. Lithological combination B, characterized by saltatory mixing of interbedded dolomitic siltstone and dolomicrite, and lithological combination A developed on the side of the sand bar near the shallow lake, while lithological combination C with blended mixing of interbedded dolomitic siltstone and silty dolomite developed on the side near provenance. Strong compaction is the main factor of the decrease of reservoir quality of sand bar reservoirs. Carbonate cementation promotes the densification of reservoirs. The irregular flaky clay minerals lead to the exponential decline of permeability, and dissolution is the main kind of diagenesis to improve reservoir quality. The dolomitic siltstone reservoirs in the middle of a single sand bar have the best reservoir quality because the overlying dolomicrite layers resist compaction, resulted in a certain amount of primary pores remained. Besides, the dolomitic siltstone reservoirs are far from the sand-mudstone interfaces, which leads to the low carbonate cement content. Furthermore, abundant dissolution pores in dolomitic siltstone reservoirs improve the reservoir quality. These research results are crucial to reservoir evaluation and development in similar mixed depositional tight reservoirs.

Carbon Capture, Utilization, and Storage (CCUS) refers to the process of capturing and separating CO₂ from emission sources such as energy utilization and industrial processes, or directly from the atmosphere, and transporting it to suitable locations for utilization or storage, in order to achieve long-term storage or conversion of CO₂. Over the past century of development, CCUS has evolved from a standby technology primarily to becoming a crucial technology for achieving net-zero emissions. Its role in addressing climate change has become increasingly important. In this context, clusters and hubs have become the hot topics in the development of CCUS. By sharing costs and risks, as well as benefits and achievements, clusters and hubs will effectively promote the large-scale application of CCUS. Currently, there are about 25 CCUS cluster or hub projects being researched or constructed worldwide. The Longship project in Norway is a typical hub project and provides valuable insights for global peers. China's three major state-owned petroleum companies are also conducting research on CCUS cluster projects. In the future, multiple CCUS cluster projects will be established in the Bohai Bay Basin, Songliao Basin, Junggar Basin, Ordos Basin, as well as the Yangtze River Delta and the Pearl River Delta regions, providing strong impetus for the development of China's CCUS industry.

Due to the capacity to quantify the complexity of a fracture network, fractal dimension (D) is widely applied in analyzing fracture network-related issues, such as connectivity and permeability. While the relationship between D and individual properties of a fracture network has been extensively studied, D is influenced by a combination of multiple attributes of the fracture network. Therefore, this work utilizes multivariate analysis to establish an equation for predicting D, taking into account various properties of the fracture network, namely fracture length, number, and orientation. Monte Carlo simulation is employed to generate a substantial number of fracture network models. Subsequently, relationships between the fractal dimension (D) and various properties are derived for three types of fracture networks with (1) invariant fracture length and random orientation, (2) exponential fracture length and random orientation, and (3) exponential fracture length and von-Mises orientation. The initial analysis focuses on the simplest relationship, wherein the fundamental formula of fractional expression is determined. Then the second and third relationships are obtained through replacing the fixed parameter in the first relationship with the distribution parameters of fracture properties. Correlation analyses between the predicted D and the actual values reveal a remarkably high correlation (>0.99). To validate the established relationships, a fracture network obtained from geological outcrops is utilized. The results demonstrate the validity of the derived relationships. The utilization of these equations enhances the efficiency, practicality, and convenience of estimating fractal dimensions from fracture properties. As a result, the analysis of fracture network-related issues becomes more feasible and accessible.

The evaluation of oil content and mobility in shale oil reservoirs is the key to the optimization of the "sweet spot" of shale reservoirs and the evaluation of available resources. In order to address the challenge of quantitative evaluation of oil content and mobility in shale oil reservoirs, a combined multi-temperature pyrolysis and NMR experimental platform and experimental procedure are innovatively designed and implemented in this paper. The experiments reveal the NMR T2 distribution characteristics of hydrocarbon components in different reserve states. Accordingly, the NMR T2 cutoff values of different hydrocarbon components are determined, and the quantitative evaluation method based on NMR logging for total oil content and movable hydrocarbon content is established. The method has been applied to the inter-salt shale oil BYY2 well in Jianghan Oilfield, and the results show that the total porosity of the shale reservoir in the Qian 4 sub-Member is similar, but the total hydrocarbon content (0.04 g/kg∼16.0 g/kg) and the movable oil content (0.02 g/kg∼4.9 g/kg) are significantly different. Compared with the preferred scheme of reservoir based on porosity, accurate quantitative evaluation results of oil content and mobility based on logging provide a more straightforward indication of the resource potential of the reservoir that is available for exploitation. The experimental scheme of multi-temperature pyrolysis-NMR and the quantitative evaluation method for oil content and motility based on NMR logging will provide an important basis for resource evaluation, optimal formation selection and efficient development of shale oil reservoirs.

The Fu 2 Member of the Paleocene Funing Formation in the Gaoyou Depression, Subei Basin is an organic matter-rich formation, and has a high potential for shale oil exploration and exploitation. Total organic carbon (TOC), organic petrography, Rock-Eval pyrolysis, chloroform bitumen “A” extraction, and SARA (saturates/aromatics/resins/asphaltenes) composition analyses of shale samples from one drill core in the studied area spanning a thickness of 257 m were conducted to study the organic matter (OM) richness, kerogen type, maceral composition, hydrocarbon generation potential, and oil content of the Fu 2 Member. Results show that the Fu 2 Member shales in the study area have a R_o of 0.87%, in the peak oil window, suggesting a high potential for hydrocarbon generation. The studied OM in shales mainly belongs to kerogen Type II, with a minor portion of Type I and Type III. Under microscopic observation, macerals in the studied shales are mainly composed of vitrinite, inertinite, alginite, and solid bitumen. The studied shales have an average TOC content of 1.41 wt%, indicating good petroleum potential. The variations of maceral compositions could affect the reliability when the Tmax is used as an indicator of thermal maturity. The lower Shale 4 and upper Shale 5 interval (3650–3700 m), with high TOC and high oil saturation index, is identified as the sweet-spot interval of the Fu 2 Member for shale oil exploration.

In order to reveal the impact of fracturing fluid retention and flowback on the development effect after large-scale fracturing in shale oil wells, and to formulate a reasonable flowback policy, this paper employs a combination of core physical simulation experiments and theoretical analysis. We have designed a specially designed device that can evaluate the development effect of quasi-natural energy in oil reservoirs. The impact of fracturing fluid retention on development is simulated by changing the amount of fracturing fluid injected into the formation in a fractured horizontal well model (referred as injection volume), and the impact on development effect is analyzed by changing the properties of fracturing fluid to adjust the difference in the degree of flowback. Based on the experimental results, the mechanism of fracturing fluid retention and flowback after large-scale fracturing in shale reservoirs is further explored. The results of the experiments show that the flowback rate of fracturing fluid exhibits a monotonic decreasing trend with increasing the volume of injected fluid, as increasing the volume of injected fluid helps to enhance its retention in the formation and reduce the flowback rate. The degree of fracturing fluid flowback is critical to the mobility of crude oil in the tight reservoir. The entering of fracturing fluid into the reservoir slows down the rate of discharge in the fracture network, effectively extending the reach of the fracturing fluid in the tight reservoir and allowing more crude oil to be used, which in turn results in higher crude oil production. However, too much injection fluid may affect the fluid production. Simulation experiments reveal that the use of fracturing fluid retention or controlling the rate of flowback by changing the viscosity of fracturing fluid can be a way to enhance the development effect of horizontal shale oil wells. The results of this paper provide a basis for understanding the mechanism of shale oil development, exploring technical ideas to improve the development effect, and making decisions on the flowback parameters.

Water-flooding reservoirs often face challenges such as low remaining geological reserves and high production costs during the high water cut stage. Well pattern thinning presents a promising solution by increasing the geological reserve controlled by the well pattern and reducing production costs, thereby enabling the economic development of water-flooding reservoirs during high water cut periods. In this paper, we have chosen the Z reservoir of CD heterogeneity oilfield as a case study to investigate and analyze various well pattern thinning schemes using reservoir numerical simulation. The impact of different fluid properties on the development effect after well pattern thinning in the Z reservoir is also investigated. An optimization model for single-well production is also developed to determine the optimal production rate after well pattern thinning. The results indicate that the production rate after well pattern thinning surpasses that before the thinning process, and further optimization of production rates post-thinning can enhance the development effect.

Temporary plugging and diversion fracturing technology play a vital role in boosting the production of tight reservoirs. The increase of net pressure in fractures is the core of temporary plugging diversion fracturing, which is closely related to the permeability of temporary plugging aggregates. However, the evolution of the permeability of temporary plugging bodies has received limited research attention. In this paper, a novel experimental system for evaluating the permeability capacity of temporary plugging agents is firstly established. This device allows us to measure critical parameters such as injection pressure, length and permeability of the temporary plugging body during the experimentation. Additionally, we assess the pressure-bearing capacity of the temporary plugging agent using a specialized experimental setup for temporarily plugging fractures. Throughout the experiment, we collect data on time consumption at different pressure levels and the volume of injected liquid. Furthermore, we conduct a comparative analysis of the pressure-bearing effects of five types of temporary plugging materials. Our experimental results reveal some interesting findings. Pure granular CDD-1 does not effectively form a substantial length, and we observe no significant relationship between the length and permeability of the temporary plugging body. In contrast, temporary plugging materials mainly composed of powder exhibit a uniform permeability of the temporary plugging body, blending both powder and particles. Moreover, temporary plugging bodies primarily formed by powder, uniform mixtures of powder and particles, and predominantly particle-based plugging bodies (with consideration of powder) demonstrate lower permeability, rendering them more favorable for temporary plugging purposes. This study sheds light on the permeability characteristics of different temporary plugging materials, contributing to a better understanding of their efficacy in temporary plugging and diversion fracturing applications. The findings could inform the selection and optimization of temporary plugging agents, ultimately enhancing the efficiency and success of tight reservoir production.

The Hurenbuqi Sag, located on the Bayinbaolige uplift in the northern Erlian Basin, is a secondary depression rich in oil. In order to study the influence on hydrocarbon accumulation of the Early Cretaceous structures in the southern Hurenbuqi Sag, the geological, drilling and geophysical data has been analyzed carefully to reveal the Early Cretaceous extensional structural characteristics, differential structural deformation characteristics, tectonic evolution process, and the hydrocarbon accumulation process. The study revealed that, extensional tectonic system is the mainly composition of Early Cretaceous structure, it has controlled the three main tectonic subsidence stages, early initial tectonic subsidence, middle rapid tectonic subsidence and late slow tectonic subsidence, of the southern Hurenbuqi Sag. During the tectonic evolution, the Early Cretaceous deformation obviously controlled the development of the source rocks and hydrocarbon accumulation. This study is of great significance for analyzing the enrichment regulations of hydrocarbon and guiding the next oil and gas exploration.