Aug 2026· Journal of Physics, Conference Series· Vol 3290, pp. 012202· 0 citations· 12 references
Physics
Abstract
The tight sandstone gas reservoirs in Area S are characterized by deep burial, strong heterogeneity, and poor petrophysical properties. Single-well productivity varies widely and declines rapidly; therefore, establishing optimal combinations of development parameters is essential for improving development efficiency. Taking the tight gas reservoir in Area S as the study object, this work integrates well logging, geological, and production dynamic data. A three-dimensional fine-scale geological model was constructed using sequential indicator simulation and sequential Gaussian simulation, and geological reserves were quantitatively evaluated using the Monte Carlo method (P50 = 4.818 × 109 m3). Based on this model, numerical simulation techniques were applied to conduct sensitivity analysis and optimization of key development parameters. The results indicate that for vertical wells in Area S, a reasonable fracture half-length ranges from 100 to 300 m with 3-4 fracturing stages; for horizontal wells, a reasonable lateral length ranges from 800 to 1000 m with a fracture half-length of approximately 100 m. For zones classified by reserve abundance, differentiated well-pattern layouts are proposed: a 900 m × 1200 m pattern for Class I zones, a 700 m × 1000 m pattern for Class II zones, and a 500 m × 700 m pattern for Class III zones. These findings provide a scientific basis and technical support for the efficient development of Area S and other similar tight gas reservoirs.
Carbonate gas reservoirs are characterized by strong heterogeneity and a complex combination of pores, fractures, and caves. The productivity of gas wells is controlled by many factors, including geology, development, and engineering factors. The traditional one-point productivity evaluation method is insufficient to accurately characterize the productivity differences in gas wells with different reservoir types. In this paper, the carbonate gas reservoir of the MK Formation in the HS 4 block is taken as the research object. Based on core characteristics, thin sections, dolomite content, and permeability data, the two main reservoir types, vuggy and fracture-vuggy, are systematically categorized. The influence of geological, development, and engineering factors on gas well productivity is analyzed using SHAP values. At the same time, to improve the accuracy and engineering practicability of gas reservoir productivity evaluation, the one-point productivity equation was refined, and open-flow capacity prediction charts for vuggy and fracture-vuggy reservoirs were constructed by combining the improved equation with the steady-state productivity equation. The results show that the dolomitization degree of vuggy reservoirs is lower than that of fracture-vuggy reservoirs, and the reservoir space types are mainly small dissolution pores or intergranular dissolution pores. The lithology of the fracture-vuggy reservoir is dolomite. The reservoir space of this type of reservoir is mainly composed of large dissolution pores and fractures, with a good matching relationship between fractures and pores. Based on the SHAP interpretation and analysis method, it is clear that cumulative water production, total acid fracturing fluid volume, gas-layer thickness, and porosity are the main factors affecting gas well productivity. Among them, the influence of cumulative water production and total acid fracturing fluid volume is the most significant, indicating that changes in the gas-water relationship and the effect of acid fracturing factors during development have a greater impact on gas well productivity. Based on the improved one-point productivity equation and the steady-state productivity equation, the open-flow prediction chart of vuggy and fracture-vuggy reservoirs is established. In predicting the gas well productivity of medium-deep reservoirs, with reconstruction scale and geological conditions similar to those of the HS 4 block, the chart’s predictions are in good agreement with field gas test and production test results. The single-well prediction error ranges from 2.2% to 6.5%, with an average error of 4.3%, indicating that the established chart has good applicability and predictive reliability. The research results can provide a theoretical and technical basis for reservoir classification evaluation, reasonable production allocation optimization, and new-well productivity prediction for carbonate gas reservoirs in the HS 4 block.
The oil-and-gas fields of the Volga-Ural basin have been developed for many decades. Nevertheless, the region still contains significant hydrocarbon reserves in carbonate formations. However, the low permeability and thin oil-bearing intervals prevent their cost-effective development. This article presents a comprehensive approach for designing development systems for such reserves, using the Orenburg oil and gas condensate field as an example. Conventional development planning method designed for terrigenous reservoir is often ineffective for complex reservoir, necessitating a revision of the method. This work focuses on identifying reservoir types by using all available data, including core, seismic, well logging, and well testing data, along with modern seismic processing techniques. By gaining a deeper understanding of the reservoir types and their spatial distribution, the author can select the most effective development strategies, including well design and stimulation methods, at the early stages of field development. The proposed comprehensive approach improves the economic performance of developing hard-to-recover reserves by up to 20% through increased production rates during the early stages of field development.
M. V. Tryapyshko· Oil and Gas Studies· 0 citations
It is very difficult to predict the productivity of a horizontal well in a tight oil reservoir after volume fracturing as many factors affect its productivity and these factors are interconnected with each other intricately. Therefore, a new productivity prediction model considering the impacts of multiple geologic and engineering factors has been proposed in this work. In this study, firstly, three-dimensional geological parameters of the study area were obtained by establishing its three-dimensional geological model. Secondly, a sweet spot evaluation model by coupling key geological parameters was established, and productivity impact factors and reservoir sweet spot factors were calculated to pick out the main factors affecting productivity and reservoir geological quality; moreover, the fracture development factor was calculated based on the rock mineral composition to assess the reservoir engineering quality. Finally, a prediction model of ultimate recoverable reserves (EUR) of horizontal wells was established based on the reservoir comprehensive quality index, to predict the productivity dynamically. The new model was adopted to predict productivities of some horizontal wells in a typical tight oil reservoir in western China. The results show that the geological factors affecting productivity in descending order are horizontal section length, reservoir thickness, oil saturation, permeability and porosity. The field application has confirmed that the reservoir comprehensive quality index has a good correlation with EUR. The productivities of 45 horizontal wells predicted by the model had an average relative error of 6.3%, proving that the model has good practicability. The research results can guide the evaluation of volume fracturing effects and schemes for horizontal wells in tight reservoirs.
Shungang Zhou, Ling-Jun Li, Liang Tao et al.· Journal of Physics, Conferen...· 0 citations
This study aims to evaluate the reservoir potential and hydrocarbon prospectivity of the Kujung Formation using an integrated well log petrophysical analysis carried out through a MATLAB-based workflow. The methodology includes qualitative quicklook interpretation to identify hydrocarbon zones, the use of various crossplot methods for lithology characterization, and quantitative calculation of key petrophysical parameters. Log anomalies caused by tool sticking were excluded to ensure the reliability of the data. The qualitative evaluation indicates that the reservoir is mainly composed of clean limestone, with a shale layer above it acting as a seal rock. Quantitative analysis shows favorable reservoir properties within the 5,500–7,400 ft interval, with an average shale volume of 9.49%, an effective porosity of 14.34%, and a water saturation of 6.88%. By applying petrophysical cutoff limits, a net pay thickness of 1,251 ft was obtained from a gross interval of 1,700 ft. These results correspond to a net-to-gross ratio of 0.736. Overall, the findings suggest that the Kujung Formation acts as a productive gas reservoir.
Gabe Bagus Arthantha, Stevy Louhenapessy, Meylisa Dwi Chandra et al.· Journal of Earth Energy Scie...· 0 citations
Hydrocarbon reservoir is conventionally treated as a single rock unit, which adversely affects productivity. In most cases, this approach is unrealistic in complex geologic environment where reservoirs have several components that contribute to the flow of hydrocarbon. This study delineates reservoir rocks into its various rock types and flow units in “D” field, offshore Niger Delta. Suites of well log (gamma ray, resistivity, sonic, density, and neutron) from three wells and core data were utilized. Conventional method of flow unit analysis, involving flow zone indicator (FZI) approach, rock physics, and
K
‐means clustering was adopted for the study. Two reservoirs, R1 and R2, were delineated, and their petrophysical properties were also computed. Petrophysical parameters showed that R1 has a gross thickness ranging from 7 to 14 m, whereas R2 ranged from 2 to 7 m. In R1, (
V
sh
) varied from 0.13 to 0.30, porosity ranged from 0.20 to 0.31, permeability varied from 1402 to 2947 mD, and hydrocarbon saturation ranged from 0.10 to 0.47. In R2,
V
sh
ranges from 0.17 to 0.32, porosity varied from 0.19 to 0.25, permeability ranged from 1247 to 2392 mD, and hydrocarbon saturation varied from 0.26 to 0.74. Three rock types, namely, poorly sorted unconsolidated sand, well‐sorted unconsolidated sand, and moderately cemented sand, were determined from compressional velocity (
V
p
) against porosity crossplot, superimposed on rock physics models. The well‐sorted and moderately cemented sandstones retained reservoir potential despite increased acoustic velocities, whereas the poorly sorted unconsolidated sands represent non‐reservoir facies due to poor consolidation and elevated clay content. Rock physics‐based
K
‐means clustering identified four flow units in Reservoir R1 and three in Reservoir R2. Using FZI‐based
K
‐means clustering, three hydraulic flow units were established in both reservoirs, which supports the rockphysics findings. FU1 exhibits the best reservoir quality. The integrated workflow has reliably characterized flow units in both cored and uncored reservoirs, thereby reducing reservoir uncertainty and supporting hydrocarbon recovery.
Olubunmi Elizabeth Adewoye, P. A. Enikanselu, M. A. Ayuk· Journal of Petroleum Geology· 0 citations
Coal-measure gas co-production is a critical strategy for enhancing the single-well productivity of unconventional natural gas. However, the pronounced vertical heterogeneity and complex combinations of co-existing reservoirs create substantial asynchronous propagation behaviors during hydraulic fracturing, fundamentally limiting the accurate prediction of multi-reservoir stimulation outcomes. This study employs numerical simulation to investigate fracture development, using the reservoir combinations of the Linxing area on the northeastern margin of the Ordos Basin as a geological model. Our results show that the thickness ratio and mechanical properties of individual rock layers are primary controls on fracture propagation. Specifically, a higher coal seam thickness ratio reduces fracture half-length but increases width, while a greater sandstone layer thickness ratio decreases width and increases height. We further propose the novel concept of the fracture propagation coefficient to characterize the heterogeneity of the fracturing process. It is found that fracture development is closely related to the distance from the injection point, the physical properties of rock layers, and the mechanical property differences between adjacent strata. The distribution of fractures is governed by the coupling effect between injection point location and reservoir mechanical properties. The reservoir–fracture response relationships established in this study provide a scientific basis for optimizing reservoir selection and fracturing parameters in coal-measure gas development.
Hao Chen, Guozhang Li, Chen Li et al.· Energies· 0 citations
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