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Journal articles on the topic 'Reservoir properties'
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1
Zhou, Tianqi, Hongqi Yuan, Fengming Xu, and Rigen Wu. "Tight Sandstone Reservoir Characteristics and Controlling Factors: Outcrops of the Shanxi Formation, Liujiang River Basin, North China." Energies 16, no. 10 (May 16, 2023): 4127. http://dx.doi.org/10.3390/en16104127.
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Tight sandstone reservoirs are of interest due to their potentially favorable prospects for hydrocarbon exploration. A better understanding of tight sandstone outcrop reservoir characteristics and their influencing factors is thus needed. By laboratory observation, thin section analysis, and experimental analysis, the current work carried out a detailed investigation of densely sampled tight sandstone outcrops of the Shanxi Formation in the Liujiang River Basin, paving the way for further research on rock types, reservoir spatial distribution, physical properties, and their key controlling factors. The application of the Pressure Pulse Attenuation Method made it possible to determine the porosity and permeability, as well as the analysis of debris composition and filling content. The findings indicate that the main rock type of the tight sandstone outcrop reservoirs in the Shanxi Formation in the Liujiang River Basin is lithic quartz sandstone, some of which contains fine sand-bearing argillaceous siltstone, giving them very low porosity (average porosity of 4.34%) and low permeability (average permeability of 0.023 mD) reservoirs. Secondary pores—mostly dissolved pores among and in grains—are widely developed in the target region. In addition, diagenesis primarily includes mechanical compaction, cementation, and dissolution. The main controlling factors of tight sandstone reservoirs in the target region are sedimentation, diagenesis, and tectonics, whereby sedimentation affects reservoir physical properties that become better as the clast size increases, reservoir properties are negatively impacted by compaction and cementation, and reservoir properties are somewhat improved due to dissolution and the impact of tectonism. In addition, the tilt of the crust will produce faults during the tectonic action, generating reservoir cracks that improve the reservoir’s physical properties. This study tends to be helpful in the prediction of high-quality reservoirs in the Permian Shanxi Formation in North China and can also be used for analogy of high-quality reservoirs in similar areas with complete outcrops.
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Miotti, Fabio, Andrea Zerilli, Paulo T. L. Menezes, João L. S. Crepaldi, and Adriano R. Viana. "A new petrophysical joint inversion workflow: Advancing on reservoir’s characterization challenges." Interpretation 6, no. 3 (August 1, 2018): SG33—SG39. http://dx.doi.org/10.1190/int-2017-0225.1.
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Reservoir characterization objectives are to understand the reservoir rocks and fluids through accurate measurements to help asset teams develop optimal production decisions. Within this framework, we develop a new workflow to perform petrophysical joint inversion (PJI) of seismic and controlled-source electromagnetic (CSEM) data to resolve for reservoirs properties. Our workflow uses the complementary information contained in seismic, CSEM, and well-log data to improve the reservoir’s description drastically. The advent of CSEM, measuring resistivity, brought the possibility of integrating multiphysics data within the characterization workflow, and it has the potential to significantly enhance the accuracy at which reservoir properties and saturation, in particular, can be determined. We determine the power of PJI in the retrieval of reservoir parameters through a case study, based on a deepwater oil field offshore Brazil in the Sergipe-Alagoas Basin, to augment the certainty with which reservoir lithology and fluid properties are constrained.
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Yin, Rongwang, Qingyu Li, Peichao Li, and Detang Lu. "A Novel Method for Matching Reservoir Parameters Based on Particle Swarm Optimization and Support Vector Machine." Mathematical Problems in Engineering 2020 (April 29, 2020): 1–10. http://dx.doi.org/10.1155/2020/7542792.
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When the reservoir physical properties are distributed very dispersedly, the matching precision of these reservoir parameters is not good. We propose a novel method for matching the reservoir physical properties based on particle swarm optimization (PSO) and support vector machine (SVM) algorithm. First, the data structure characteristics of the reservoir physical properties are analyzed. Then, the particle swarm differential perturbation evolution algorithm is used to cluster and characterize the reservoir physical properties. Finally, by using the SVM algorithm for feature reorganization and the least squares matching of the extracted reservoir physical properties, the feature quantity of the reservoir physical properties can be accurately mined and the pressure matching precision is improved. The experimental results show that employing the proposed method to analyze and sample the data characteristics of the physical properties of the reservoir is better. The extracted parameters can effectively reflect the physical characteristics of oil reservoirs. The proposed method has potential applications in guiding the exploration and development of oil reservoirs.
4
Shin, Seungwon, Sangbeen Lee, Sungsu Lee, and Jongwon Jung. "Evaluation of Slope Stability of Reservoir Considering Heterogeneous Soil Properties." Journal of the Korean Society of Hazard Mitigation 20, no. 6 (December 31, 2020): 167–75. http://dx.doi.org/10.9798/kosham.2020.20.6.167.
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The slope stability evaluation of reservoirs is required because of the aging of reservoirs. Reservoir levees are designed to achieve homogeneous construction, but the spatial heterogeneity of the material properties of reservoirs is unavoidable. Because the existing method for evaluating reservoir stability is limited in terms of considering the spatial heterogeneity of material properties, the stability evaluation was conducted in this study, in which the spatial heterogeneity and uncertainty of the material properties of the reservoir levee were considered. In addition, the results for the existing and proposed methods were compared and analyzed, and the variability of the entire material properties of the reservoir levee, instead of spatial heterogeneity, was reflected. The evaluation results confirmed that the probability of failure obtained using the proposed method was lower than that for the existing stability evaluation method, considering the variations in material properties because the levee did not reach the critical state, owing to changes in local properties. Therefore, the proposed method is useful for the cost-effect repair and reinforcement of reservoir slopes, compared to the existing slope stability evaluation method.
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Yang, Tao, Ibnu Hafidz Arief, Martin Niemann, and Marianne Houbiers. "Reservoir Fluid Data Acquisition Using Advanced Mud-Logging Gas in Shale Reservoirs." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 65, no. 4 (August 1, 2024): 455–69. http://dx.doi.org/10.30632/pjv65n4-2024a2.
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Oil production from shale reservoirs has increased dramatically in recent years. To identify drilling targets and optimize well completions, it is important to get early access to reservoir fluid properties. However, due to the low permeability of shale reservoirs, fluid samples often become available only after the most important development decisions have been made. Therefore, it has been an abiding challenge in the industry how to acquire fluid properties data earlier in shale reservoirs. Mud-logging gas data acquired while drilling provide the earliest hydrocarbon response from the reservoir. In an earlier study, we demonstrated that advanced mud gas data have a large potential to predict reservoir fluid properties. In general, fluid properties are strongly correlated with the thermal maturity of the source rock. In shale reservoirs, reservoir fluids are still in the source rock, as low permeability limits the migration and convection of the reservoir fluids. As a result, the reservoir fluid systems in shale reservoirs are relatively undisturbed and have a high degree of consistency. This provides the possibility to correlate advanced mud-logging gas data and reservoir fluid properties. Based on a reservoir fluid database with more than 60 samples from different shale reservoirs, we developed a machine-learning algorithm to predict fluid properties from advanced mud-logging gas data. The accuracy of the new method is significantly improved compared with the previous model, which used an explicit correlation based on wetness. In addition, the new approach is more general and does not depend on a specific shale reservoir. We applied the new model to 11 wells with advanced mud-logging gas data. The predicted gas-oil ratios (GOR) are close to the measurement from early production data when advanced mud-logging gas data are of good quality. This publication demonstrates that advanced mud-logging gas data can be used to predict reservoir fluid properties in shale reservoirs. Such an approach provides a novel and cost-efficient solution for the sampling challenges in the early phase. In addition, the method provides continuous fluid data along the entire well, as opposed to a single fluid sample taken at a specific location. Hence, the results provide insight into the fluid distribution in shale reservoirs. The method can be widely used for sweet spot identification and optimizing fracking strategy in shale reservoirs.
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Valluri, Manoj Kumar, Jimin Zhou, Srikanta Mishra, and Kishore Mohanty. "CO2 Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding." Energies 13, no. 23 (November 26, 2020): 6215. http://dx.doi.org/10.3390/en13236215.
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Process understanding of CO2 injection into a reservoir is a crucial step for planning a CO2 injection operation. CO2 injection was investigated for Ohio oil reservoirs which have access to abundant CO2 from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO2 under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO2 injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone.
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Abdulrazzaq, Tuqa, Hussein Togun, Dalia Haider, Mariam Ali, and Saja Hamadi. "Determining of reservoir fluids properties using PVTP simulation software- a case study of buzurgan oilfield." E3S Web of Conferences 321 (2021): 01018. http://dx.doi.org/10.1051/e3sconf/202132101018.
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The measurement of oil reservoirs and their performance with hydrocarbon reservoirs is used to distinguish the properties of reservoir fluids, which is significant in various reservoir studies. As a result, in the various oil industries, adopting the appropriate methods to obtain accurate property values is very important. The current paper is about a case study of the BUZURGAN Oilfield and how the PVTp software was used to predict phase activity and physical properties. To understand the properties of fluids for the reservoir and phase behavior, the black oil model and the equation of state (EoS) model are used. (Glaso) correlation is used to calculate the bubble point strain, solubility, and formation volume factor. The Beal's correlation was also used to measure viscosity, while the equation of state (EoS) model was used to determine phase behavior and density. Furthermore, the properties of PVT were discovered using the software, and the results were compared to laboratory analysis of PVT, with suitable models being displayed. According to the findings, the used model has the highest saturation pressure, which was chosen for use in reservoir management processes and the preparation of a geological model to reflect the field later. It is clear that the program is appropriate due to the accurate dependence of PVT measurements on laboratory tests in the case that tests are required during the reservoir's productive existence.
8
Hussein, Marwa, Robert R. Stewart, Deborah Sacrey, Jonny Wu, and Rajas Athale. "Unsupervised machine learning using 3D seismic data applied to reservoir evaluation and rock type identification." Interpretation 9, no. 2 (April 21, 2021): T549—T568. http://dx.doi.org/10.1190/int-2020-0108.1.
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Net reservoir discrimination and rock type identification play vital roles in determining reservoir quality, distribution, and identification of stratigraphic baffles for optimizing drilling plans and economic petroleum recovery. Although it is challenging to discriminate small changes in reservoir properties or identify thin stratigraphic barriers below seismic resolution from conventional seismic amplitude data, we have found that seismic attributes aid in defining the reservoir architecture, properties, and stratigraphic baffles. However, analyzing numerous individual attributes is a time-consuming process and may have limitations for revealing small petrophysical changes within a reservoir. Using the Maui 3D seismic data acquired in offshore Taranaki Basin, New Zealand, we generate typical instantaneous and spectral decomposition seismic attributes that are sensitive to lithologic variations and changes in reservoir properties. Using the most common petrophysical and rock typing classification methods, the rock quality and heterogeneity of the C1 Sand reservoir are studied for four wells located within the 3D seismic volume. We find that integrating the geologic content of a combination of eight spectral instantaneous attribute volumes using an unsupervised machine-learning algorithm (self-organizing maps [SOMs]) results in a classification volume that can highlight reservoir distribution and identify stratigraphic baffles by correlating the SOM clusters with discrete net reservoir and flow-unit logs. We find that SOM classification of natural clusters of multiattribute samples in the attribute space is sensitive to subtle changes within the reservoir’s petrophysical properties. We find that SOM clusters appear to be more sensitive to porosity variations compared with lithologic changes within the reservoir. Thus, this method helps us to understand reservoir quality and heterogeneity in addition to illuminating thin reservoirs and stratigraphic baffles.
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Novruzova, S. H., and I. N. Aliyev. "Determination of Reservoir Characteristics Oil Well Producing Non-Newtonian Oil, Taking into Account the Temperature Situation in the Reservoir." Oil and Gas Technologies 150, no. 1 (2024): 40–42. http://dx.doi.org/10.32935/1815-2600-2024-150-1-40-42.
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The article investigates the problem of determining the reservoir properties of non-Newtonian oil reservoirs developed in the depletion mode, the rocks of which are subjected to elastic deformation. Various methods (identification and graphic-analytical) for determining the reservoir properties of non-Newtonian oil reservoirs are proposed, takinginto account the temperature situation. The determined reservoir properties of the formations are: porosity and permeability of the formations, the initial pressure gradient, as well as the current well drainage radius.
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Mondal, Samit, Rima Chatterjee, and Shantanu Chakraborty. "An integrated approach for reservoir characterisation in deep-water Krishna-Godavari basin, India: a case study." Journal of Geophysics and Engineering 18, no. 1 (February 2021): 134–44. http://dx.doi.org/10.1093/jge/gxab002.
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Abstract The Miocene reservoirs in prolific Krishna-Godavari basin are mostly fluvial deposits and laminated or blocky in nature. The type of reservoir quality depends on associated geological environments. Due to several lateral variations in reservoir properties, a similar kind of workflow for reservoir characterisation does not work. Customised workflow needs to be applied in this area for estimation of petrophysical properties or rock physical analysis for reservoir quality prediction. As the major input of rock physical analysis is petrophysical properties, it is crucial to estimate these properties accurately. Meanwhile, it is also important to check the seismic sensitivity to change in fluid saturation in the reservoir characterisation process. The analysis assures the presence of reservoir and hydrocarbon contact in seismic sensitivity, which is essential for removing risk. Integrating the geological model with rock physical analysis for reservoir characterisation at the drilled well, the reservoir quality at undrilled prospects is predicted. In this study, the comprehensive study for reservoir characterisation of Miocene reservoirs consists of three different steps: calculation of petrophysical properties for mixed of thick and laminated sequence, rock physical analysis for identification of hydrocarbon reservoir and corresponding seismic sensitivity for change in saturation and finally the rock physics template for prediction of reservoir quality away from the drilled well. Results from the study have added significant value in de-risking the number of undrilled prospects in this area.
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Farouk, Ali Khaleel, and Ayad A. Al-haleem. "Integrating Petrophysical and Geomechanical Rock Properties for Determination of Fracability of the Iraqi Tight Oil Reservoir." Iraqi Geological Journal 55, no. 1F (June 30, 2022): 81–94. http://dx.doi.org/10.46717/igj.55.1f.7ms-2022-06-22.
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Tight oil reservoirs have been a concerned of the oil industry due to their substantial influence on oil production. Due to their poor permeability, numerous problems are encountered while producing from tight reservoirs. Petrophysical and geomechanical rock properties are essential for understanding and assessing the fracability of reservoirs, especially tight reservoirs, to enhance permeability. In this study, Saadi B reservoir in Halfaya Iraqi oil field is considered as the main tight reservoir. Petrophysical and geomechanical properties have been estimated using full-set well logs for a vertical well that penetrates Saadi reservoir and validated with support of diagnostic fracture injection test data employing standard equations and correlations. Subsequently, breakdown pressures are computed, and two fracturing models have been developed. The petrophysical analysis infers that the reservoir has poor properties, while the findings of the geomechanical properties indicate that the reservoir is brittle with ductile rock strata. These ductile strata underlay and overlay more brittle formations than the reservoir. The results from diagnostic fracture injection test DFIT are quite consistent with well logs results. The breakdown pressure reflects that this reservoir could easily be fractured by inserting pressure equal to 6250 psi. However, the fracturing model design parameters manipulates the fracture height confinement within Saadi Formation and its propagation to Hartha and/or Tanuma Formations. Therefore, the employment of petrophysical and geomechanical properties of the rocks assists in understanding the fracability of the formation and demonstrating the orientation and the fracture propagation direction.
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Yuan, Bin, Zhenzihao Zhang, and Christopher R. Clarkson. "Improved Distance-of-Investigation Model for Rate-Transient Analysis in a Heterogeneous Unconventional Reservoir With Nonstatic Properties." SPE Journal 24, no. 05 (July 2, 2019): 2362–77. http://dx.doi.org/10.2118/191698-pa.
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Summary The concept of distance of investigation (DOI) has been widely applied in rate– and pressure–transient analysis for estimating reservoir properties and for optimizing hydraulic fracturing. Despite its successful application in conventional reservoirs, significant errors arise when extending the concept to unconventional reservoirs. This work aims to clearly demonstrate such errors when using the traditional square–root–of–time model for DOI calculations in unconventional reservoirs, and to develop new models to improve the DOI calculations. In this work, the following mechanisms in unconventional reservoirs are first incorporated into the calculation of DOI: (1) pressure–dependency of rock and fluid properties; (2) continuous/discontinuous spatial variation of reservoir properties. To achieve this, pseudopressure, pseudotime, and pseudodistance are introduced to linearize the diffusivity equation. Two novel methods are developed for calculating DOI: one using the concept of continuous succession of steady states, and the other using the concept of dynamic drainage area (DDA). Both models are verified using a series of fine–grid numerical simulations. A production–data–analysis workflow using the new DOI models is proposed to analytically characterize reservoir heterogeneity and fracture properties. The new DOI models compensate for the inability of the traditional square–root–of–time model to capture spatial and temporal variations of reservoir and fluid properties. The pressure–dependency of fluids and reservoirs (i.e., fluid density, fluid viscosity, rock permeability, and rock porosity) and reservoir heterogeneities (i.e., deterioration of reservoir quality from the primary fracture to the reservoir) can significantly retard the propagation of the DOI. Another important outcome of this work is to provide a practical and analytical approach to directly estimate the spatial heterogeneity from the production history of field cases.
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Jing, Yajie, Zhiwu Zhang, Peng Xu, and Shasha Yang. "Reservoir characteristics of Chang 2 Member of Yanchang Formation in Area A, Ordos Basin." E3S Web of Conferences 290 (2021): 03011. http://dx.doi.org/10.1051/e3sconf/202129003011.
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With the continuous enhancement of exploration and development in the Ordos Basin, in-depth research has been carried out on the petrological and reservoir characteristics of Chang 2 reservoir in Area A, which provides a geological basis for the efficient development of oil reservoirs. Comprehensive use of reservoir sandstone thin section identification casting analysis, mercury intrusion analysis, logging analysis and other methods to systematically study the petrological characteristics, pore characteristics and reservoir physical properties of Chang 2 reservoir in Area A. The results show that the reservoirs in the study area are dominated by fine-grained sandstones, with low component maturity and high structural maturity. They are all medium-low porosity, low-permeability and ultra-low permeability reservoirs. Primary intergranular pores and residual intergranular pores are developed, the reservoir drainage pressure is low, which is good-medium, and the mercury removal efficiency is high, indicating that the reservoir has good storage performance and seepage properties.
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Dai, Jinyou, Lixin Lin, and Rui Wang. "A New Method to Determine the Lower Limit of Reservoir Physical Properties—Corrected Minimum Flow Pore-throat Radius Method." E3S Web of Conferences 290 (2021): 03004. http://dx.doi.org/10.1051/e3sconf/202129003004.
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The lower limit of reservoir physical properties is an important parameter for identifying reservoirs and determining effective thickness in reserves evaluation, and is also an important basis for selecting perforated test intervals in oilfield exploration and development. There are many methods to determine the lower limit of reservoir physical properties, and the minimum flow pore throat radius method is one of the commonly used methods. The method uses 0.1μm as the minimum flow pore-throat radius, and uses this to calibrate the lower limit of reservoir physical properties. However, according to the water film theory, the minimum radius of the reservoir's flowing pore throat is not a definite value, but varies with the displacement dynamics. Therefore, there is no exact basis for using 0.1μm as the minimum flow pore-throat radius, so it needs to be corrected. To this end, a new method for determining the lower limit of reservoir physical properties—the corrected minimum flow pore-throat radius method is proposed. The correction method comprehensively considers the factors of oil and gas accumulation dynamics, and determines the lower limit of reservoir physical properties by obtaining the minimum flow pore-throat radius value suitable for oil and gas accumulation dynamics. A case study of Chang 63 reservoir in A Oilfield shows that the minimum flow pore radius of oil and gas determined by the correction method is 0.08 μm, and the lower limit of reservoir physical properties (porosity 9.1%, permeability 0.117 × 10-3 μm2). The traditional method has a minimum flow pore-throat radius of 0.1 μm and a lower limit of reservoir physical properties (porosity of 9.8% and permeability of 0.133 × 10-3 μm2). Due to full consideration of the impact of oil and gas accumulation dynamics, the minimum flow pore-throat radius determined by the correction method is more reliable than the traditional method, and the lower limit of the reservoir physical property calibrated by it has practical significance.
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Pierpont, Rob, Kristoffer Birkeland, Alexandra Cely, Tao Yang, Li Chen, Vladislav Achourov, Soraya S. Betancourt, et al. "Enigmatic Reservoir Properties Deciphered Using Petroleum System Modeling and Reservoir Fluid Geodynamics." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 64, no. 1 (February 1, 2023): 6–17. http://dx.doi.org/10.30632/pjv64n1-2023a1.
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Two adjacent reservoirs in offshore oil fields have been evaluated using extensive data acquisition across multiple disciplines; several surprising observations were made. Differing levels of biodegradation were measured in the nearly adjacent reservoirs, yet related standard geochemical markers are contradictory. Unexpectedly, the more biodegraded oil had less asphaltene content, and this reservoir had some heavy end deposition in the core but upstructure, not at the oil-water contact (OWC) as would be expected, especially with biodegradation. Wax appears to be an issue in the nonbiodegraded oil. These many puzzling observations, along with unclear connectivity, gave rise to uncertainties about field development planning. Combined petroleum systems and reservoir fluid geodynamic considerations resolved the observations into a single, self-consistent geo-scenario, the co-evolution of reservoir rock and fluids in geologic time. A spill-fill sequence of trap filling with biodegradation helps explain differences in biodegradation and wax content. A subsequent, recent charge of condensate, stacked in one fault block and mixed in the target oil reservoir in the second fault block, explains conflicting metrics of biodegradation between C7 vs. C16 indices. Asphaltene instability and deposition at the upstructure contact between the condensate and black oil, and the motion of this contact during condensate charge, explain heavy end deposition in core. Moreover, this process accounts for asphaltene dilution and depletion in the corresponding oil. Downhole fluid analysis (DFA) asphaltene gradients and variations in geochemical markers with seismic imaging clarify likely connectivity in these reservoirs. The geo-scenario provides a benchmark of comparison for all types of reservoir data and readily projects into production concerns. The initial apparent puzzles of this oil field have been resolved with a robust understanding of the corresponding reservoirs and development strategies.
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Liu, Sheng, Hongtao Zhu, Qianghu Liu, Ziqiang Zhou, and Jiahao Chen. "Along-Strike Reservoir Development of Steep-Slope Depositional Systems: Case Study from Liushagang Formation in the Weixinan Sag, Beibuwan Basin, South China Sea." Energies 16, no. 2 (January 10, 2023): 804. http://dx.doi.org/10.3390/en16020804.
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Seismic, core, drilling, logging, and thin-section data are considered to analyze the reservoir diversity in the east, middle, and west fan of the Liushagang Formation in the steep-slope zone of the Weixinan Sag, Beibuwan Basin. Three factors primarily affect the reservoir differences for steep-slope systems: (1) Sedimentary factors mostly control reservoir scales and characteristics and the drainage system and microfacies. Massive high-quality reservoirs have shallow burial depths. Channel development and sediment supply favor the formation of these reservoirs. The sedimentary microfacies suggest fan delta plain distributary channels. (2) Lithofacies factors primarily control reservoir types and evolution. The diagenesis of high-quality reservoirs is weak, and a weak compaction–cementation diagenetic facies and medium compaction–dissolution diagenetic facies were developed. (3) Sandstone thickness factors primarily control the oil-bearing properties of reservoirs. The average porosity and permeability of high-quality reservoirs are large, the critical sandstone thickness is small, the average sandstone thickness is large, and the oil-bearing capacity is high. Furthermore, the reservoir prediction models are summarized as fan delta and nearshore subaqueous fan models. The high-quality reservoir of the fan delta model is in the fan delta plain, and the lithology is medium–coarse sandstone. The organic acid + meteoric freshwater two-stage dissolution is developed, various dissolved pores are formed, and a Type I reservoir is developed. The high-quality reservoir of the nearshore subaqueous fan model is in the middle fan, and the lithology is primarily medium–fine sandstone. Only organic acid dissolution, dissolution pores, and Type I–II reservoirs are developed. Regarding reservoir differences and models, the high-quality reservoir of the steep-slope system is shallow and large-scale, and the reservoir is a fan delta plain distributary channel microfacies. Weak diagenetic evolution, good physical properties, thick sandstone, and good oil-bearing properties developed a Type I reservoir. The study of reservoir control factors of the northern steep-slope zone was undertaken in order to guide high-quality reservoir predictions. Further, it provides a reference for high-quality reservoir distribution and a prediction model for the steep-slope system.
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Jiangmin, Du, Zhang Xiaoli, Yu Yanqiu, Huang Kaiwei, Guo Hongguang, Zhong Gaorun, Yu Bowei, and Zhao Yuanyuan. "Lacustrine Carbonate Reservoir Characteristics Research of Jurassic Da’anzhai Member in North Central Sichuan Basin." Open Petroleum Engineering Journal 8, no. 1 (September 10, 2015): 398–404. http://dx.doi.org/10.2174/1874834101508010398.
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Based on both macroscopic and microscopic characteristics of cores from Lower Jurassic Da’anzhai Member in north central Sichuan Basin, and combined with physical property data, a detail study has been conducted, which includes reservoir characteristics such as lithologic characters, physical properties, and reservoir space types, and control factors of reservoir development. The study suggests that, there are two typical kinds of reservoirs: crystalline shell limestone and argillaceous shell limestone. The reservoirs properties are poor with ultra-low porosity and low permeability, which can be significantly improved by fractures. Reservoir space type is pore-fracture, mainly constitutive of the micro-fractures accompanied by dissolved pores. The reservoir development is controlled by sedimentation, diagenesis and tectogenesis together. Shell beach and lacustrine slop are the favorable facies for reservoir development. Dissolution is the primary constructive diagenesis to improve reservoir porosity and permeability. Structural fractures are necessary for reservoir effectiveness and high production.
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Zhang, Xuejuan, Lei Zhang, Dandan Wang, Kuo Lan, Xuesong Zhou, Hongyu Yu, Ruhao Liu, and Xueying Lv. "Nonuniform grid upscaling method for geologic model of oil reservoir: A case study of the W block in the northern part of the Songliao Basin." Interpretation 9, no. 2 (April 7, 2021): T443—T452. http://dx.doi.org/10.1190/int-2020-0112.1.
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At present, uniform upscaling division methods are routinely used to upscale geologic model grids, resulting in overly fine grids in some areas of the model. To improve computational efficiency, we have examined the effect of model upscaling with different upscaling parameters with the goal of producing a nonuniform grid with uniform accuracy. We based our nonuniform upscaling grid method on geologic characteristics including reservoir thickness, physical properties, reservoir spacing, and water flooding. Most of the logging curves of thin reservoirs are finger-like, allowing us to define the grid size according to the reservoir thickness. We use two different strategies to discretize uniform and composite reservoirs and represent reservoir thickness that exhibit bell- and funnel-shaped logging curves. Although one grid point accurately represents a uniform reservoir, we find that composite reservoirs require four or five points to accurately represent the physical properties of a composite reservoir. For the thick reservoirs (>5 m) with box- or composite-type logging curves, the physical properties inside the reservoir do not change much; therefore, we use a grid point to represent the reservoir thickness information. Using these metrics, we constructed alternative “moderate” and “efficient” vertical grid upscaling strategies. Taking the 15 sedimentary units with a total thickness of 72 m as an example, the statistical results show that the computational efficiency using our data-adaptive grid can be increased more than five times compared to the traditional uniform fine-grid method while retaining the same accuracy.
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Andrew Emuobosa Esiri, Dazok Donald Jambol, and Chinwe Ozowe. "Enhancing reservoir characterization with integrated petrophysical analysis and geostatistical methods." Open Access Research Journal of Multidisciplinary Studies 7, no. 2 (June 30, 2024): 168–79. http://dx.doi.org/10.53022/oarjms.2024.7.2.0038.
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Reservoir characterization is a critical aspect of hydrocarbon exploration and production, providing essential insights into reservoir properties, fluid behavior, and potential production performance. This review presents an overview of the application of integrated petrophysical analysis and geostatistical methods in enhancing reservoir characterization. The integration of petrophysical analysis and geostatistical methods enables a comprehensive understanding of reservoir properties and heterogeneities, leading to more accurate reservoir models and improved reservoir management strategies. Petrophysical analysis involves the interpretation of well log data, core measurements, and laboratory experiments to quantify reservoir properties such as porosity, permeability, fluid saturations, and lithology. Geostatistical methods, including variogram analysis, spatial interpolation, and stochastic simulation, are used to spatially model reservoir properties and uncertainties, integrating available data and capturing spatial variability. Key benefits of integrating petrophysical analysis and geostatistical methods include enhanced reservoir characterization, improved reservoir modeling accuracy, optimized well placement and production strategies, and reduced exploration and development risks. Case studies demonstrate the application of integrated approaches in various reservoir settings, including clastic, carbonate, and unconventional reservoirs, highlighting the effectiveness of these methods in improving reservoir understanding and performance prediction. Challenges and limitations associated with integrated petrophysical analysis and geostatistical methods include data quality and availability, uncertainty quantification, computational complexity, and model validation. Addressing these challenges requires a multidisciplinary approach, involving collaboration between geoscientists, reservoir engineers, petrophysicists, and data scientists, as well as advancements in data acquisition, processing, and modeling techniques. The integration of petrophysical analysis and geostatistical methods offers significant opportunities for enhancing reservoir characterization and improving reservoir management practices. By leveraging available data and integrating multidisciplinary expertise, operators can achieve a better understanding of reservoir behavior, optimize production strategies, and maximize hydrocarbon recovery from subsurface reservoirs. Continued research and innovation in integrated reservoir characterization techniques are essential for addressing challenges and unlocking the full potential of hydrocarbon resources in a sustainable and efficient manner.
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Asubiojo, T. M., and S. E. Okunuwadje. "Petrophysical evaluation of reservoir sand bodies in Kwe Field Onshore Eastern Niger Delta." Journal of Applied Sciences and Environmental Management 20, no. 2 (July 25, 2016): 383–93. http://dx.doi.org/10.4314/jasem.v20i2.21.
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Reservoir sand bodies in Kwe Field, coastal swamp depobelt, onshore eastern Niger Delta Basin were evaluated from a composite log suite comprising gamma ray, resistivity, density and neutron logs of five (5) wells with core photographs of one (1) reservoir of one well. The aim of the study was to evaluate the petrophysical properties of the reservoirs while the objectives were to identify the depositional environment and predict the reservoir system quality and performance. The study identified three reservoir sand bodies in the field on the basis of their petrophysical properties and architecture. Reservoir A has an average NTG (61.4 %), Ø (27.50 %), K (203.99 md), Sw (31.9 %) and Sh (68.1 %); Reservoir B has an average NTG (65.6 %), Ø (26.0 %), K (95.90 md), Sw (28.87 %) and Sh (71.13 %) while Reservoir C has an average NTG (70.4 %), Ø (26.1 %), K (91.4 md), Sw (25.0 %) and Sh (75.03 %) and therefore show that the field has good quality sandstone reservoirs saturated in hydrocarbon. However, the presence of marine shales (or mudstones) interbedding with these sandstones may likely form permeability baffles to vertical flow and compartmentalize the reservoirs. These reservoirs may therefore have different flow units. Integrating wireline logs and core data, the reservoir sand bodies were interpreted as deposited in an estuarineshoreface setting thus indicating that the Kwe Field lies within the marginal marine mega depositional environment.Keywords: Estuarine, Shoreface, Reservoir, Sand, Kwe, field
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Sattam, Mohammed, Safaa Hameed, and Rasha Al-Ali. "Enhancement Petrophysical Properties of Carbonate Reservoirs Using Plasma Channel Technology, Case Study: Yamama Formation, South of Iraq." Iraqi Geological Journal 57, no. 2A (July 31, 2024): 230–40. http://dx.doi.org/10.46717/igj.57.2a.16ms-2024-7-26.
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Carbonate reservoirs are significant hydrocarbon productions, but their complex and heterogeneous nature often poses challenges in maximizing oil and gas recovery. Traditional methods for enhancing petrophysical properties have shown limited success in carbonate formations. However, new advancements in Plasma Channel Technology have shown promising results in improving the reservoir's petrophysical properties. The application of Plasma Channel Technology is considered as a novel approach to enhance the petrophysical properties of carbonate reservoirs. Plasma channel technology involves the controlled application of high-voltage electrical discharges to create conductive channels (new porosity) within the reservoir units. These channels serve as preferential pathways for fluid flow (permeability) and facilitate enhanced oil and gas recovery. The main objective of this study is to show the key aspects of the enhancement of the Yamama reservoir properties using Plasma Channel Technology minimizes the need for chemical additives to reduce operational costs and environmental impact. Therefore, Yamama Formation is studied in two oil wells Snd-1 and Snd-2, six core samples from reservoir units within the Yamama succession were studied to determine porosity using a Scanning Electron Microscope which provides valuable insights into their internal structure and porosity characteristics in these samples. A comparison had been done between porosities within rock samples before and after application of Plasma channel technology, where the porosity was ranging from micropores (10 nm) to mesopores (10-50 nm) in some samples before voltage electrical discharges, while it reached mesopores (20-50 nm) to macropores (more than 500 nm) after voltage electrical discharges.These pores have been increased in size if there was higher voltage which means enhancement in the petrophysical properties in the reservoir.
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Kerimova, K. A., and L. N. Khalilova. "Assessment of petrophysical properties of reservoirs by well data." Azerbaijan Oil Industry, no. 09 (September 15, 2024): 5–12. http://dx.doi.org/10.37474/0365-8554/2024-09-5-12.
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The use of traditional research complexes is of great importance in solving such important problems as correlating well sections for the purpose of lithological assessment, determining the reservoir properties of reservoir layers that make up the section, namely, saturation, porosity, permeability and clay content, as well as identifying oil and gas-bearing and aquifer layers. The complexity of solving such important problems depends entirely on the petrophysical properties of reservoir layers. For example, the electrical resistivities of oil-bearing and aquifer reservoirs are similar in magnitude, which leads to high clay content and significant variation in porosity throughout the field, which, as a result, makes it difficult to separate oil-bearing and aquifer reservoirs from each other. On the other hand, it is also known that an increase in the amount of cementing clays in reservoirs leads to a decrease in porosity and an increase in residual water saturation. In this regard, in the article, based on a set of well data, the values of the petrophysical parameters of reservoir layers were determined, models were built that determine the correlation between them, and regression equations based on the statistical distribution of these parameters were established. The article also built models for the distribution of porosity, permeability, clay content and oil and gas saturation along well sections. The constructed models provide the basis for forming a definite opinion about the field and obtaining results of both a scientific and practical nature when studying the filtration and reservoir characteristics of reservoir layers, as well as when determining the relationship between petrophysical parameters. The object of the study was the on the Kirmakinskaya (KS) and Underkirmaky (UK) formations of the productive series (PS) selected from the wells of the Gyurgyan-Deniz field.
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Crump, James G., and Robert H. Hite. "A New Method for Estimating Average Reservoir Pressure: The Muskat Plot Revisited." SPE Reservoir Evaluation & Engineering 11, no. 02 (April 1, 2008): 298–306. http://dx.doi.org/10.2118/102730-pa.
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Summary This paper describes a new method for estimating average reservoir pressure from long-pressure-buildup data on the basis of the classical Muskat plot. Current methods for estimating average reservoir pressure require a priori information about the reservoir and assume homogeneous reservoir properties or use empirical extrapolation techniques. The new method applies to heterogeneous reservoirs and requires no information about reservoir or fluid properties. The idea of the method is to estimate from the pressure derivative the first few eigenvalues of the pressure-transient decay modes. These values are characteristic of the reservoir and fluid properties, but not of the pressure history or well location in the reservoir. The smallest eigenvalue is used to extrapolate the long-time behavior of the transient to estimate the final reservoir pressure. The second eigenvalue can be used to estimate the quality of the estimate. Numerical tests of the method show that it estimates average reservoir pressure accurately, even when the reservoir is heterogeneous or when partial-flow barriers are present. Examples with real data show that the behavior predicted by the theory is actually observed. We expect the method to have value in reservoir limits testing, in making consistent estimates of average reservoir pressure from permanent downhole gauges, and in characterizing complex reservoirs. Introduction Several different methods of interpreting pressure-buildup data to obtain average reservoir pressure have been proposed (Muskat 1937; Horner 1967; Miller et al. 1950; Matthews et al. 1954; Dietz 1965) in the past, and in recent years some new techniques have appeared in the literature (Mead 1981; Hasan and Kabir 1983; Kabir and Hasan 1996; Kuchuk 1999; Chacon et al. 2004). Larson (1963) revisited the Muskat method and put it on a firm theoretical ground for a homogeneous cylindrical reservoir. Some of the existing techniques depend on knowledge of the reservoir size and shape and assume homogeneous properties (Horner 1967; Miller et al. 1950; Matthews et al. 1954; Dietz 1965). Such methods may result in uncertain predictions when reservoir data are unavailable or reservoir heterogeneity exists. The inverse time plot by Kuchuk (1999) is essentially a modification of Horner's method (1967) and works well in reservoirs that can be treated as infinite during the time of the test. The hyperbola method proposed by Mead (1981) and further developed by Hasan and Kabir (1983) is an empirical technique, not based on fundamental fluid flow principles for bounded reservoirs (Kabir and Hasan 1996). Chacon et al. (2004) develop the direct synthesis technique, in which conventional theory is used to derive an average pressure directly from standard log-log plots. Homogeneous properties and radial symmetry are assumed. Muskat's original derivation was a wellbore storage model. Larson reinterpreted Muskat's method and derived relationships showing how Muskat's plot could be used to estimate average reservoir pressure in a cylindrical, homogeneous reservoir. This paper revisits the ideas underlying Larson's paper. Similar ideas are shown to hold for heterogeneous reservoirs of any shape. A new analysis technique replacing the Muskat plot by a plot of the pressure derivative simplifies the determination of average reservoir pressure. It is shown that parameters from analysis of a long buildup on a reservoir can be used in subsequent buildup tests to shorten the required time of the subsequent buildups. Finally, estimates for time required for a buildup in homogeneous reservoirs of any shape are given.
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Li, Zhi Jun, and Shu Qing Li. "Physical Properties and Main Controlling Factors of Low-Permeability Sandstone Gas Reservoir." Applied Mechanics and Materials 246-247 (December 2012): 592–97. http://dx.doi.org/10.4028/www.scientific.net/amm.246-247.592.
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In order to guide the resource prediction and exploration evaluation of low-permeability sandstone gas reservoir, the physical properties of this kind of gas reservoir are summarized from such aspects as lithology, porosity, permeability and the characteristics of capillary force, and the main controlling factors of the gas reservoir are analyzed. The analysis show that low-permeability sandstone gas reservoir is mainly characteristic of high capillary pressure, high bound water saturation, low and high porosity as well as low permeability. Rock composition and structural characteristics of the reservoir is the basis of the factors that can affect the compactness of the reservoir. The formation of the reservoir is mainly affected by deposition, diagenesis and late tectogenesis: deposition can affect the composition of minerals, the original physical properties of clastic sediments and others; diagenesis is the main stages of the densification of reservoir, where compaction, pressure solution, cementation and late dissolution are the causes of the densification of reservoir. Dissolution and rim chlorite cementation improve reservoir property; tectonization can have an effect of late transformation on the physical properties of clastic reservoir. At the same time, the fluid characteristics in the reservoir can also affect the permeability of reservoirs.
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Zhang, Jing Jun, Cheng Zhi Liu, Yong Liang Yang, and Si Hai Yu. "Volcanic Oil and Gas Reservoir Characteristics and Comprehensive Evaluation in Oulituozi Area." Advanced Materials Research 671-674 (March 2013): 328–32. http://dx.doi.org/10.4028/www.scientific.net/amr.671-674.328.
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Based on the core, thin section, scanning electron microscopy, well logging and the physical properties of reservoir, according to the research on the volcanic reservoirs characteristics of the E2-3S3 Formation in Oulituozi area, obtaining the following points: Basalt, trachyte and tuff are mainly lithology, overflow facies are main lithofacies, secondly explosive facies and volcanic sedimentary facies; Secondary reservoir spaces are often superimposed on the original reservoir spaces, and pore, hole and slit together form the effective reservoir spaces; The reservoir property show that the trachyte are the best, secondly the basalt and tuff; Reservoir lithology, lithofacies, thickness, fracture development, physical and electrical properties and other reservoir parameters are the main evaluation criteria to conduct the reservoir comprehensive evaluation.
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Ahmed, Rayan. "Geological Model for Mauddud Reservoir Khabaz Oil Field." Iraqi Geological Journal 54, no. 1D (April 30, 2021): 29–42. http://dx.doi.org/10.46717/igj.54.1d.3ms-2021-04-23.
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The Mauddud reservoir, Khabaz oil field which is considered one of the main carbonate reservoirs in the north of Iraq. Recognizing carbonate reservoirs represents challenges to engineers because reservoirs almost tend to be tight and overall heterogeneous. The current study concerns with geological modeling of the reservoir is an oil-bearing with the original gas cap. The geological model is establishing for the reservoir by identifying the facies and evaluating the petrophysical properties of this complex reservoir, and calculate the amount of hydrocarbon. When completed the processing of data by IP interactive petrophysics software, and the permeability of a reservoir was calculated using the concept of hydraulic units then, there are three basic steps to construct the geological model, starts with creating a structural, facies and property models. The reservoirs were divided into four zones depending on the variation of petrophysical properties (porosity and permeability). Nine wells that penetrate the Cretaceous Formation (Mauddud reservoir) are included to construct the geological model. Zone number three characterized as the most important due to it Is large thickness which is about 108 m and good petrophysical properties are about 13%, 55 md, 41% and 38% for porosity, permeability, water saturation and net to gross respectively. The initial oil and gas in place are evaluated to be about 981×106 STB and 400×109 SCF.
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Alsultan, Hamid, Maha Manhi, Shahad Abas, and Amer Al-Khafaj. "Quantitative Interpretation of the Petrophysical Properties of Selected Wells for the Mishrif Formation in Nasiriyah Oilfield, Southern Part of Iraq." Iraqi Geological Journal 57, no. 1B (February 29, 2024): 149–60. http://dx.doi.org/10.46717/igj.57.1b.12ms-2024-2-21.
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One of the oil field's main reservoirs is the Mishrif Formation, which is found in the Nasiriyah oilfield in the southern part of Iraq (Late Cenomanian-Early Turonian). It was one of the three oil wells selected for this study. To extract various petrophysical parameters for open wells indicated by gamma ray, density, neutron, self-potential, acoustic, and resistance, a variety of well logs were analyzed. The qualitative interpretation of the logs allowed for the identification of different types of rocks, the boundaries and thicknesses of the strata, the depths of the formation, and the zones that contained water and hydrocarbons. The quantitative interpretation, which assesses the reservoir's attributes by computing its porosity, the quantity and distribution of the shales, the levels of water and oil saturation, and other elements, that are necessary to evaluate the reservoir’s units in the research wells. The features of the study wells and the used logs were reported, to make clear how these features were distributed among the sample wells. The collected petrophysical characteristics were handled and shown as charts. There are two types of units within the Mishrif Formation: reservoir-containing CR-I, MA, CR-II, and MB. In most wells, reservoir units are made up of hard, low-porous rocks that are positioned between highly porous reservoir units. For a few wells, the MA unit had low residual and mobile hydrocarbon percentages, whereas the MB unit had large percentages, while the hard rocks had significant percentages of water saturation.
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Shen, Yinghao, Xinyu Yang, and Yuelei Zhang. "Production Analysis of Tight Sandstone Reservoir in Consideration of Stress-Sensitive Permeability." Open Petroleum Engineering Journal 10, no. 1 (April 28, 2017): 82–93. http://dx.doi.org/10.2174/1874834101710010082.
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Background: Tight sandstone reservoirs play an important role in the oil industry. The permeability of tight sandstone reservoir generally has stronger stress sensitivity than that of conventional reservoir because of the latter’s poor physical properties. However, the production analysis of tight sandstone reservoir did not fully considered the stress-sensitive permeability yet. Objective: This paper proposed a production analysis method considering the stress- sensitive permeability. Method: This paper firtstly investigated the stress sensitivity characteristics and the effect of stress-sensitive permeability on a tight reservoir. Decline-type curves that consider stress-sensitive permeability are then established, and a systematic analysis method was built for the production analysis to obtain the single-well controlled dynamic reserves and reservoir physical properties. Results: A field analysis was performed in combination with Block Yuan-284 of Changqing Oilfield. Results show that with the reduction of reservoir pressure, stress sensitivity leads to the decline in reservoir permeability and the increase in seepage resistance, thus reducing the actual single-well controlled reserve and radius. Conclusion: By utilizing the analysis method based on the decline curves, we can effectively predict the single-well controlled dynamic reserves of such reservoirs and evaluate the characteristic parameters of reservoirs.
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Gorain, Surajit. "Geo-Body and Geostatistical Modelling of Carbonate Reservoir Facies Architecture and Characterization." International Journal of Petroleum Technology 10 (August 2, 2023): 26–38. http://dx.doi.org/10.15377/2409-787x.2023.10.3.
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Carbonate reservoirs present significant challenges in characterizing and extracting hydrocarbons due to their low permeability, matrix heterogeneities, fractures, and dissolution patterns. Accurately predicting the facies architecture and reservoir properties in such complex formations has been a persistent challenge for geoscientists. This paper proposes an integrated approach that combines geo-body extraction and geostatistical modeling to accurately predict the facies architecture and reservoir properties in carbonate reservoirs. The methodology begins by generating 3D seismic root mean square amplitude (RMS) attributes, which are then used to extract geo-bodies along the pay sequences. The extracted geo-bodies are then subjected to geostatistical modeling to analyze reservoir properties to facilitate the optimization of drilling and production strategies. To validate the effectiveness of the proposed approach, a small field in the Mumbai offshore basin is chosen as a case study. This field is located on the Mumbai High-Deep Continental Shelf and exhibits westerly dipping structures. Structural mapping confirms the presence of an antiformal structure, with one particular well (D-8) at the crest showing the absence of hydrocarbons. The proposed approach mapped two seismic reflectors within the reservoir zones and generated window-based 3D seismic RMS attributes to extract three geo-bodies within the reservoir. Facies and property modeling revealed the presence of distinct non-reservoir facies with poor reservoir properties near dry wells (D-8, D-4, and D-7), which is in line with the production performance observed in the drilled wells. The proposed integrated approach of geo-body extraction and geostatistical modeling is effective in delineating the facies architecture and reservoir heterogeneity of carbonate reservoirs. It enables the identification of favorable reservoir facies and facilitates a comprehensive assessment of the remaining potential.
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Onda, Chihaya, Tetsuya Sumi, and Tsuyoshi Asahi. "Planning and Analysis of Sedimentation Countermeasures in Hydropower Dams Considering Properties of Reservoir Sedimentation." Journal of Disaster Research 13, no. 4 (August 1, 2018): 702–8. http://dx.doi.org/10.20965/jdr.2018.p0702.
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Sedimentation in hydropower reservoirs is one of the most important problems facing power generation. Many of the reservoirs our company’s dams, built in the postwar reconstruction period, have been storing up sedimentation for decades. The percentage of sedimentation is now considerable, about 9%, because of a combination of a high degree of sediment production and the river flow regime. We have been trying to excavate the sedimentation from the reservoirs to avoid aggradations of upstream riverbeds and to eliminate obstacles to intake and outlet functions. Considering sediment properties, we have carried out representative five different ways of managing reservoir sediment. At the Sakuma dam, which is comparatively large, provisional transporting inside the reservoir is the main countermeasure, but radical management will be required in the near future. At the Futatsuno dam and Taki dam, which are medium-sized, the current volume of sedimentation excavation is not sufficient to maintain the size of the reservoir, due to flow sedimentation. Sediment routing methods, such as bypassing, will therefore be urgently planned. At the Setoishi and Yambara dams, the testing of sediment sluicing or hydro-suction sediment removal systems has already started. Regarding sedimentation sluicing, we have studied the feasibility of sediment bypass tunnels and gated outlets in the dam reservoir that is unsuitable for sluicing with the existing spillway. We found that gated outlet will be effective. Although there are no quick remedies that can reduce reservoir sedimentation dramatically, there are some methods that may be suitable, considering the size, life and basin of each reservoir. Not only the technical feasibility, but also the economic advantages and ecological acceptability should be considered. To sustain reservoirs and hydropower, sedimentation should be managed effectively and adaptively, based on the specific conditions of each reservoir.
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Zhang, Lei. "Water Flooding Curve in Determining the A Reservoir Water Flood Sweep Efficiency." Advanced Materials Research 650 (January 2013): 681–83. http://dx.doi.org/10.4028/www.scientific.net/amr.650.681.
Full textAbstract:
A reservoir in the Jurassic natural water drive development of sandstone reservoirs, reservoir rock sandstone and siltstone and fine particle size, carbonatites cement content less, does not affect the reservoir properties. A reservoir average porosity of 18% and average permeability of 45 × 10-3μm2, belongs in porosity and low permeability reservoir, and the reservoir was not continuous development, strong heterogeneity. A reservoir development characteristics, application of water flooding curve and the related empirical formula A reservoir water flooding sweep efficiency.
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Othman, Adel, Mohamed Fathy, and Islam A. Mohamed. "Application of Artificial Neural Network in seismic reservoir characterization: a case study from Offshore Nile Delta." Earth Science Informatics 14, no. 2 (January 19, 2021): 669–76. http://dx.doi.org/10.1007/s12145-021-00573-x.
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AbstractThe Prediction of the reservoir characteristics from seismic amplitude data is a main challenge. Especially in the Nile Delta Basin, where the subsurface geology is complex and the reservoirs are highly heterogeneous. Modern seismic reservoir characterization methodologies are spanning around attributes analysis, deterministic and stochastic inversion methods, Amplitude Variation with Offset (AVO) interpretations, and stack rotations. These methodologies proved good outcomes in detecting the gas sand reservoirs and quantifying the reservoir properties. However, when the pre-stack seismic data is not available, most of the AVO-related inversion methods cannot be implemented. Moreover, there is no direct link between the seismic amplitude data and most of the reservoir properties, such as hydrocarbon saturation, many assumptions are imbedded and the results are questionable. Application of Artificial Neural Network (ANN) algorithms to predict the reservoir characteristics is a new emerging trend. The main advantage of the ANN algorithm over the other seismic reservoir characterization methodologies is the ability to build nonlinear relationships between the petrophysical logs and seismic data. Hence, it can be used to predict various reservoir properties in a 3D space with a reasonable amount of accuracy. We implemented the ANN method on the Sequoia gas field, Offshore Nile Delta, to predict the reservoir petrophysical properties from the seismic amplitude data. The chosen algorithm was the Probabilistic Neural Network (PNN). One well was kept apart from the analysis and used later as blind quality control to test the results.
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Isgandarov, M. M., A. H. Abuzarova, E. G. Kerimova, and A. S. Gumbatov. "Heterogeneity of reservoirs of the Qala suite (on the example of the Neft Dashlary field)." Scientific Petroleum, no. 1 (June 30, 2023): 6–11. http://dx.doi.org/10.53404/sci.petro.20230100034.
Full textAbstract:
In order to study the heterogeneity of reservoir rocks based on core materials and well logging data, an analysis of the lithological-petrographic and reservoir properties of the rocks of the Qala suite of the PS of the Neft Dashlary field was carried out. For a more detailed study, an analysis of laboratory data on subformations (QaS1, QaS2, QaS3 and QaS4) has been carried out, the grainsize composition and reservoir properties (porosity, clay content, permeability and carbonate content) of reservoir rocks were studied. Based on the results of logging data interpretation and analysis of the constructed correlation schemes, heterogeneity, including the study of reservoirs thickness and the variability of their reservoir properties over the area have been studied. Keywords: Kalinskaya suite; Core; Logging; Heterogeneity.
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Popova, Oksana A., and Oleg O. Uraev. "Facies models of hydrocarbon-bearing formations of Podneytinskiy reservoir at Bovanenkovskoye and Kharasaveyskoye fields." PROneft’. Proffessional’no o nefti 6, no. 4 (December 24, 2021): 43–53. http://dx.doi.org/10.51890/2587-7399-2021-6-4-43-53.
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Background. Significant part of hydrocarbons at Bovanenkovskoye and Kharasaveyskoye fields are contained in Podneytinskiy reservoir, and study of geological features of its productive strata is important for development planning for the fields in a whole.
Aim. The paper reflects the results of integrating well and seismic data to characterize the formations of Podneytinskiy reservoir at Bovanenkovskoye and Kharasaveyskoye fields.
Materials and methods. As part of the study, sedimentological description of core was analyzed, the core, well logging and seismic survey information were assessed, and the facies schemes were prepared.
Results. As a result of the work, the reservoir architecture features and the distribution of reservoir properties of the target interval were revealed. It has been established that the considered formations of Podneytinskiy reservoir can be divided into two parts, the lower one is represented by deposits of predominantly deltaic origin, and the upper one is of continental and subcontinental genesis. The sedimentary conditions of rocks influenced the complexity of their architecture, so, in the formations referred to the lower part of the studied interval, the reservoirs, as a rule, are laterally continuous, in contrast to the deposits of the upper part of the section, which are typically characterized by extremely high lateral heterogeneity. Depositional conditions also influenced the reservoir properties of productive sediments. As a result of the work, it was revealed that the reservoirs of better quality are formed in fluvial and tidal channels, distributary channels and proximal parts of deltas, they have higher reservoir properties, are characterized by thicker sandstone interlayers and lower portion of carbonated interlayers in comparison with reservoirs formed in other conditions.
Conclusions. The article provides quantitative characteristics of reservoir properties depending on sedimentary conditions. The results obtained form the basis for creation of geological models of Bovanenkovskoye and Kharasaveyskoye fields.
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Smith, Steven Shawn, and Ilya Tsvankin. "Sensitivity of compaction-induced multicomponent seismic time shifts to variations in reservoir properties." GEOPHYSICS 78, no. 5 (September 1, 2013): T151—T163. http://dx.doi.org/10.1190/geo2012-0361.1.
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Pore-pressure variations inside producing reservoirs result in excess stress and strain that influence the arrival times of reflected waves. Inversion of seismic data for pressure changes requires better understanding of the dependence of compaction-induced time shifts on reservoir pressure reduction. Using geomechanical and full-waveform seismic modeling, we investigate pressure-dependent behavior of P-, S-, and PS-wave time shifts from reflectors located above and below a rectangular reservoir embedded in a homogeneous half-space. Our geomechanical modeling algorithm generates the excess stress/strain field and the stress-induced stiffness tensor as linear functions of reservoir pressure. Analysis of time shifts obtained from full-waveform synthetic data shows that they vary almost linearly with pressure for reflectors above the reservoir, but become nonlinear for reflections from the reservoir or deeper interfaces. Time-shift misfit curves computed with respect to noise-contaminated data from a reference reservoir for a wide range of pressure reductions display well-defined global minima corresponding to the actual pressure. In addition, we evaluate the influence of the reservoir width on time shifts and the possibility of constraining the width using time-lapse data. We also discuss the impact of moderate perturbations in the strain-sensitivity coefficients (i.e., third-order stiffnesses) on time shifts and on the accuracy of pressure inversion. Our feasibility analysis indicates that the most stable pressure estimation from noisy data is provided by multicomponent time shifts from reflectors below the reservoir. For multicompartment reservoirs, time shifts can be accurately modeled by linear superposition of the excess stress/strains computed for the individual compartments.
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Maju-Oyovwikowhe, E. G., and A. D. Osayande. "Hydrocarbon evaluation and distribution in Well-X and Well-Y in the Niger Delta Basin: Findings and validation through porosity comparison." Scientia Africana 22, no. 1 (June 14, 2023): 255–78. http://dx.doi.org/10.4314/sa.v22i1.22.
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The aim of this study is to integrate well logs and core data to identify reservoir characteristics and determine the reservoir's petrophysical properties in order to improve the understanding of the reservoir and provide valuable information for reservoir management. Wells X and Y of the ‘SCOJAS’ Field in the Niger Delta Basin of Nigeria were analyzed using Gamma ray logs, Resistivity logs, Sonic, Neutron and Density Logs. The obtained results were compared with core data from the wells to verify their accuracy. Porosity values for Wells X and Y fall within the range typically observed in sedimentary rocks, with Well Y having higher values. Hydrocarbons were detected in all reservoirs except reservoir zone 1b in both Well-X (12 reservoirs) and Well-Y (7 reservoirs). In Well- X, oil was identified in 5 reservoir zones while in Well-Y, oil was present in 2 reservoir zones. The remaining zones in both wells contained gas. To validate the results further, a comparison was made with the porosity of selected fields in the Niger Delta Basin and the general porosity of the Basin. Well X has a porosity range of 2.7% to 20.8%, which is generally lower than the reported porosity range Well Y has a porosity range of 19.90% to 24.38%, which falls at the upper end of the reported porosity range. Comparing previous works and data from other fields provides important validation for the findings of the study, which is crucial in the oil and gas industry for making informed decisions about exploration and production.
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Wei, Qin Lian, and Ling Xiao. "The Reservoir Plane Heterogeneity Characteristics of the Number 2 of the Shanxi Formation in Changbei Gas Field, Ordos Basin, China." Advanced Materials Research 524-527 (May 2012): 81–84. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.81.
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Reservoir plane heterogeneity means the geometry，the scale，the continuity and the plan variation of physical properties of reservoirs, which is one of the main factors influencing the injection-production in oil reservoirs. Therefore, the study of the reservoir plane heterogeneity play a great role in guiding development wells deployment，gas reservoir well nets adjustment and residual oil & gas development. The reservoir heterogeneity of the sandstone size of gas and the border, and unbalanced formation pressure because of the degree of the development of each well is uneven prevent ChangBei gas field to develoment. They cause difficulty of evaluating the gas field comprehensive，level development wells deployment and well trajectory adjustment，and lead to certain geology risk. It is necessary to study the reservoir heterogeneity of the number 2 of shanxi Formation in this block for concerning the unfavourable extraction condition. The composite index of reservoir plane heterogeneity of the number 2 of shanxi Formation in ChangBei gas field have calculated by adopting entropy method considering influcing reservoir plane heterogeneity which is porosity, tight sandstone, mutation coefficient and variation coefficient of permeability, range of permeability and interlayer frequency. The distributive maps of reservoir's plane heterogeneity under the restriction of sedimentary facies have also been drawed. The entropy method can full use of the reduction and strengthen of entropy method,which means the characteristic of removing the similarities and depositing differences. The study indicate that reservoir plane heterogeneity of the number 2 of shanxi Formation in study area presents the medium to slightly strong characteristics in general.
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Kokymbayeva, G., E. Ermekov, and R. Dosniyazov. "Modeling of PVT properties within the Taisogan block on the example of the Uaz, Uaz East, Uaz North fields." Engineering Journal of Satbayev University 144, no. 3 (2022): 41–49. http://dx.doi.org/10.51301/ejsu.2022.i3.07.
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The availability of reliable data on the PVT properties of reservoir fluids plays a leading role in calculating the reserves of oil and gas reservoirs, estimating the oil recovery factor, well testing, numerical reservoir modeling and for making informed decisions in field development design. In practice, the results of field, laboratory and theoretical studies are used simultaneously to substantiate the properties of natural hydrocarbon mixtures. At each of the noted stages, specialists strive to increase the reliability of the data obtained and develop methods for their interpretation. Determining the properties of reservoir fluids of an oil field is a prerequisite for the effective use of various methods of influencing the bottomhole zone of wells, selection of equipment for well operation. The properties of reservoir fluids are determined by various thermobaric conditions and change depending on the current state of the reservoir and the characteristics of reservoir pressure changes. All known methods for determining the properties of formation fluids are divided into two groups: experimental and computational. Each of the groups has both advantages and certain disadvantages.
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Yang, Yue, Xiang Fang Li, Ke Liu Wu, Jian Yang, Jun Tai Shi, and Jie Fan. "A Novel Deliverability Equation for Shallow Layer and Low Permeability Reservoirs with Horizontal Fracture." Advanced Materials Research 616-618 (December 2012): 1000–1007. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.1000.
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In order to predict the productivity of vertical well for shallow layer and low permeability reservoirs with horizontal fracture, based on the theory of horizontal fracture distribution and oil seepage in reservoir, establish the reservoir seepage physical model for shallow layer and low permeability reservoirs with horizontal fracture, and derive a novel deliverability equation, considering the effect of reservoir properties, fluid properties, horizontal fracture parameters and working systems. Furthermore, the equation was applied and performed sensitivity analysis to the productivity of a vertical well in Yanchang Chang 6 layer reservoir. Results show that vertical permeability, oil viscosity and the semiminor axis of horizontal fracture have more significant impact on well productivity. With real cases, it is demonstrated the established deliverability equation is simple and practical and meets the engineering accuracy requirements.
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Arief, Ibnu Hafidz, and Tao Yang. "A Machine-Learning Approach to Predict Gas-Oil Ratio Based on Advanced Mud Gas Data." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 65, no. 4 (August 1, 2024): 433–54. http://dx.doi.org/10.30632/pjv65n4-2024a1.
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Mud gas data from drilling operations provide the first indication of hydrocarbons in the reservoir. It has been a dream for decades in the oil industry to predict reservoir gas and oil properties from mud gas data because it would provide knowledge of the reservoir fluid properties in an early stage, continuously for all reservoir zones, and at low costs. Previous efforts reported in the literature did not lead to a reliable method for quantitative prediction of the reservoir fluid properties from mud gas data. In this paper, we propose a novel approach based on machine learning that enables us to predict gas-oil ratio (GOR) from advanced mud gas (AMG) data. The current work is based on a previous successful pilot in unconventional (shale) reservoirs to predict GOR from the C1 to C5 compositions present in AMG data. We aim to extend the results of the pilot study to conventional reservoirs. In general, the prediction of reservoir fluid properties is more challenging for conventional reservoirs than for unconventional reservoirs due to the complexity of petroleum systems in conventional reservoirs. Instead of building a model directly from AMG data, we trained a machine-learning model using a well-established database of reservoir fluid with more than ,000 pressure-volume-temperature (PVT) samples. After a thorough investigation of the compositional similarity of C1 to C5 between PVT samples and AMG data, we applied the model developed from PVT samples to AMG data. The predicted GORs from AMG data were compared with GOR measurements from corresponding PVT samples to assess the accuracy of the GOR predictions. The results from 22 wells with both AMG data and corresponding PVT samples show a large agreement between prediction and measurement. The accuracy of the predictive model (MAPE 35%) has a significant improvement compared to the results from existing empirical correlations reported in the literature (MAPE 60%). In addition, a quality check (QC) metric was developed to efficiently flag low-quality AMG data. The QC metric is vital to give a confidence level for GOR prediction based on AMG data when PVT samples are not available. This study confirms that AMG data can be used as a new data source to quantitatively predict continuous reservoir fluid properties in the drilling phase for conventional reservoirs. The new method can provide early access to reservoir fluid distribution for optimization of wireline operations for exploration wells. GOR prediction based on the new method can be used for real-time decisions on well placement, perforation, completion, and potential sidetracks for production wells. After high-quality PVT data become available from the wireline logging or production phase, the continuous GOR prediction can be further improved and used for reservoir management and production optimization.
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Zhang, Deping, Chengkai Fan, and Dongqin Kuang. "Impact assessment of interlayers on geological storage of carbon dioxide in Songliao Basin." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 85. http://dx.doi.org/10.2516/ogst/2019059.
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Reservoirs in the Songliao Basin are characterized by strong heterogeneity, which increases the difficulty of exact reservoir prediction. The clay interlayer developed in the reservoir is an important factor affecting the heterogeneity of the reservoir. Using the reservoir numerical simulation technology, an attempt has been made to investigate the storage efficiency during CO2 sequestration in Songliao Basin considering different types of interlayer in underground formations. Results indicate that type I interlayer, with a large thickness embedded between the two sand bodies has function of shunting and blocking to alleviate the impacts on cap rock. The type II interlayer has a small thickness and locates inside a single sand body, with poor physical properties and continuity, which has the same blocking effect on CO2 distribution and moderating influence on the cap rock. The physical properties of type III interlayer are same as the type II interlayer, but it has uneven distribution and poor continuity. In addition, three schemes of perforated zone were designed and their effects on CO2 storage efficiency and stability were studied. For a single reservoir, the scheme I is to perforate a whole reservoir, which is more conducive to maintain the reservoir’s stability. For multiple sets of “single-reservoir”, the scheme II can be preferentially selected to perforate the reservoir section below the interlayer when the injection volume is small. However, the scheme III can be used to perforate the interlayer and the reservoir below that when the injection volume is large. The study is beneficial to provide guidance and advice for selecting a suitable CO2 geological storage and reduce the risk of CO2 leakage.
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Wang, Wenkai, Shiqi Liu, Shuxun Sang, Ruibin Du, and Yinghai Liu. "A Study on the Production Simulation of Coal–Shale Interbedded Coal Measure Superimposed Gas Reservoirs under Different Drainage Methods." Processes 11, no. 12 (December 13, 2023): 3424. http://dx.doi.org/10.3390/pr11123424.
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To study the influence of different drainage methods on the production performance of coal measure gas wells, the interbedded reservoir composed of coal and shale in the Longtan Formation of the Dahebian block was used as the research object. Considering the influence of coal and shale matrix shrinkage, effective stress, and interlayer fluid flow on reservoir properties such as fluid migration behavior and permeability, a fluid–solid coupling mathematical model of coal measure superimposed gas reservoirs was established. Numerical simulations of coal measure gas production under different drainage and production modes were conducted to analyze the evolution of reservoir pressure, gas content in the matrix, permeability, and other characteristic parameters of the superimposed reservoir, as well as differences in interlayer flow. The results showed that, compared to single-layer drainage, cumulative gas production increased by 33% under multi-layer drainage. Both drainage methods involve interlayer energy and substance transfer. Due to the influence of permeability, porosity, and mechanical properties, significant differences exist in reservoir pressure distribution, preferential flow direction, gas content in the matrix, and permeability ratio between coal and shale reservoirs under different drainage and production modes. Multi-layer drainage effectively alleviates the influence of vertical reservoir pressure differences between reservoir layers, facilitates reservoir pressure transmission in shale reservoirs, enhances methane desorption in shale matrices, promotes matrix shrinkage, and induces the rebound of shale reservoir permeability, thus improving overall gas production.
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Sone, Hiroki, and Mark D. Zoback. "Mechanical properties of shale-gas reservoir rocks — Part 1: Static and dynamic elastic properties and anisotropy." GEOPHYSICS 78, no. 5 (September 1, 2013): D381—D392. http://dx.doi.org/10.1190/geo2013-0050.1.
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Understanding the controls on the elastic properties of reservoir rocks is crucial for exploration and successful production from hydrocarbon reservoirs. We studied the static and dynamic elastic properties of shale gas reservoir rocks from Barnett, Haynesville, Eagle Ford, and Fort St. John shales through laboratory experiments. The elastic properties of these rocks vary significantly between reservoirs (and within a reservoir) due to the wide variety of material composition and microstructures exhibited by these organic-rich shales. The static (Young’s modulus) and dynamic (P- and S-wave moduli) elastic parameters generally decrease monotonically with the clay plus kerogen content. The variation of the elastic moduli can be explained in terms of the Voigt and Reuss limits predicted by end-member components. However, the elastic properties of the shales are strongly anisotropic and the degree of anisotropy was found to correlate with the amount of clay and organic content as well as the shale fabric. We also found that the first-loading static modulus was, on average, approximately 20% lower than the unloading/reloading static modulus. Because the unloading/reloading static modulus compares quite well to the dynamic modulus in the rocks studied, comparing static and dynamic moduli can vary considerably depending on which static modulus is used.
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Guo, Peng, and George A. McMechan. "Sensitivity of 3D 3C synthetic seismograms to anisotropic attenuation and velocity in reservoir models." GEOPHYSICS 82, no. 2 (March 1, 2017): T79—T95. http://dx.doi.org/10.1190/geo2016-0321.1.
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Anisotropic attenuation in fluid-saturated reservoirs with high fracture density may be diagnostic for reservoir characterization. Wave-induced mesoscale fluid flow is considered to be the major cause of intrinsic attenuation at exploration seismic frequencies. We perform tests of the sensitivity, of anisotropic attenuation and velocity, to reservoir properties in fractured HTI media based on the mesoscale fluid flow attenuation mechanism. The viscoelastic T-matrix, a unified effective medium theory of global and local fluid flow mechanisms, is used to compute frequency-dependent anisotropic attenuation and velocity for ranges of reservoir properties, including fracture density, orientation, fracture aspect ratio, fluid type, and permeability. The 3D 3C staggered-grid finite-difference anisotropic viscoelastic modeling with a Crank-Nicolson scheme is used to generate seismograms using the frequency-dependent velocity and attenuation computed by the viscoelastic T-matrix. A standard linear solid model relates the stress and strain relaxation times to the frequency-dependent attenuation, in the relaxation mechanism equation. The seismic signatures resulting from changing viscoelastic reservoir properties are easily visible. Velocity becomes more sensitive to the fracture aspect ratio when considering fluid flow compared with when the fluid is isolated. Anisotropy of attenuation affects 3C viscoelastic seismic data more strongly than velocity anisotropy does. Analysis of the influence of reservoir properties, on seismic properties in mesoscale fluid-saturated fractured reservoirs with high fracture density, suggests that anisotropic attenuation is a potential tool for reservoir characterization.
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Obi, Ifeanyichukwu S., K. Mosto Onuoha, Olusegun T. Obilaja, and C. I. Princeton Dim. "Understanding reservoir heterogeneity using variography and data analysis: an example from coastal swamp deposits, Niger Delta Basin (Nigeria)." Geologos 26, no. 3 (December 1, 2020): 207–18. http://dx.doi.org/10.2478/logos-2020-0020.
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Abstract For efficient reservoir management and long-term field development strategies, most geologists and asset managers pay special attention to reservoir chance of success. To minimise this uncertainty, a good understanding of reservoir presence and adequacy is required for better ranking of infill opportunities and optimal well placement. This can be quite challenging due to insufficient data and complexities that are typically associated with areas with compounded tectonostratigraphic framework. For the present paper, data analysis and variography were used firstly to examine possible geological factors that determine directions in which reservoirs show minimum heterogeneity for both discrete and continuous properties; secondly, to determine the maximum range and degree of variability of key reservoir petro-physical properties from the variogram, and thirdly, to highlight possible geological controls on reservoir distribution trends as well as areas with optimal reservoir quality. Discrete properties evaluated were lithology and genetic units, while continuous properties examined were porosity and net-to-gross (NtG). From the variogram analysis, the sandy lithology shows minimum heterogeneity in east-west (E–W) and north-south (N–S) directions, for Upper Shoreface Sands (USF) and Fluvial/Tidal Channel Sands (FCX/TCS), respectively. Porosity and NtG both show the least heterogeneity in the E–W axis for reservoirs belonging to both Upper Shoreface and Fluvial Channel environments with porosity showing a slightly higher range than NtG. The vertical ranges for both continuous properties did not show a clear trend. The Sequential Indicator Simulation (SIS) and Object modelling algorithm were used for modelling the discrete properties, while Sequential Gaussian Simulation (SGS) was used for modelling of the continuous properties. Results from this exercise show that depositional environment, sediment provenance, topographical slope, sub-regional structural trends, shoreline orientation and longshore currents, could have significant impacts on reservoir spatial distribution and property trends. This understanding could be applied in reservoir prediction and for generating stochastic estimates of petrophysical properties for nearby exploration assets of similar depositional environments.
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Al Kattan, Wafa, Sameer N. AL Jawad, and Haider Ashour Jomaah. "Cluster Analysis Approach to Identify Rock Type in Tertiary Reservoir of Khabaz Oil Field Case Study." Iraqi Journal of Chemical and Petroleum Engineering 19, no. 2 (June 30, 2018): 9–13. http://dx.doi.org/10.31699/ijcpe.2018.2.2.
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Rock type identification is very important task in Reservoir characterization in order to constrict robust reservoir models. There are several approaches have been introduced to define the rock type in reservoirs and each approach should relate the geological and petrophysical properties, such that each rock type is proportional to a unique hydraulic flow unit. A hydraulic flow unit is a reservoir zone that is laterally and vertically has similar flow and bedding characteristics. According to effect of rock type in reservoir performance, many empirical and statistical approaches introduced. In this paper Cluster Analysis technique is used to identify the rock groups in tertiary reservoir for Khabaz oil field by analyses variation of petrophysical properties data that predicted by analysis of well log measurements. In tertiary reservoir four groups identified by cluster analysis technique, were each group was internally similar in petrophysical properties and different from others groups.
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Nikolaevna, Palyanitsina, and Sukhikh Sergeevich. "Peculiarities of assessing the reservoir properties of clayish reservoirs depending on the water of reservoir pressure maintenance system properties." Journal of Applied Engineering Science 18, no. 1 (2020): 10–14. http://dx.doi.org/10.5937/jaes18-24544.
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Li, Yong, Shijia Chen, Wen Qiu, Kaiming Su, and Bingyan Wu. "Controlling factors for the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation, Guang’an Area, Sichuan Basin." Energy Exploration & Exploitation 37, no. 1 (October 10, 2018): 26–43. http://dx.doi.org/10.1177/0144598718803224.
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Tight sandstone gas characterized by a wide distribution, local enrichment and a complex gas–water distribution has high exploration potential. This study, using the Xujiahe Formation in the Guang’an gas field as an example, aims to determine the main controlling factors of the enrichment of tight gas through comprehensive analyses of the source rock and reservoir characteristics, pressure evolution and structural effects by using various methods including well logging, geochemistry, mercury injection, reservoir physical properties and formation pressure. The results show that the proximal-source, interbedded hydrocarbon accumulation results from a dispersed hydrocarbon supply, which is the root cause of the widely distributed tight sandstone gas. The abnormally high reservoir pressure caused the enrichment of tight sandstone gas even under insufficient hydrocarbon generation dynamics; in addition, natural gas preferentially accumulated in the relatively high-quality reservoirs under the same hydrocarbon supply, which means that differences in the reservoir physical properties control gas charge in the reservoir. Structure controls the gas–water differentiation under the stable tectonic background, and the higher the structure is, the more abundant the gas–water differentiation is, and the easier pure gas reservoirs form. Therefore, the accumulation and enrichment of tight sandstone gas in the Xujiahe Formation is controlled by source rocks, abnormally high reservoir pressure and the physical properties and structure of the reservoir.
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Feyzullayev, A. A., A. G. Gojayev, and I. M. Mamedova. "Features of fluid dynamics in long-term heterogeneous gas reservoirs." Gornye nauki i tekhnologii = Mining Science and Technology (Russia) 7, no. 1 (April 12, 2022): 18–29. http://dx.doi.org/10.17073/2500-0632-2022-1-18-29.
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Geological features are characterized by macro- and micro-heterogeneity, manifested by the spatial variability of material composition and lithophysical properties of rocks. This, in turn, determines the spatial and temporal variability of hydrocarbon (HC) fluid dynamics both during the reservoir formation and during its development and, subsequent operation as an underground gas storage facility (UGSF). The long-term operation of underground gas reservoirs at the Galmas and Garadagh areas in the South Caspian Basin (SCB), serving as a reservoir of commercial gas accumulations, and subsequent underground gas storage (UGSF) is characterized by significant peculiarities. Analysis of monitoring data on volumes of gas injection and extraction at the Galmas/Garadagh UGSF in the period of 2020–2021 showed their spatial variability, as well as the variability of wells deliverability during the gas reservoir development. This suggests the inherited nature of UGSF operation mode in relation to the gas reservoir development mode. The heterogeneous nature of spatial variability of these parameters is determined by the reservoir rock poroperm properties. A formation pressure drop during reservoir development is accompanied by decreasing rock permeability. When operating UGSF, the lithofacial properties of rocks determine the ratio of volumes of injected and extracted gas. In this regard, a necessary condition for selecting the optimal system of UGSF operation is to take into account the spatial heterogeneity of the underground reservoir. The irregular nature of variation of rock poroperm properties, the origination of isolated zones in the reservoir with considerable residual gas volumes, as well as unpredictable directions of fluid movement are the main reasons for decreased efficiency of field development and underground gas storage facility operation. In order to determine the optimal system of operation of UGSF in depleted underground oil and gas reservoirs, the features of the spacial variations resulting from the rocks poroperm properties need to be taken into account.
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Li, Qing, Xuelian You, Yuan Zhou, Yu He, Renzhi Tang, and Jiangshan Li. "Reservoir Characterization of Alluvial Glutenite in the Guantao Formation, Bohai Bay Basin, East China." Minerals 14, no. 3 (March 16, 2024): 317. http://dx.doi.org/10.3390/min14030317.
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Alluvial glutenite reservoirs have obviously stronger heterogeneous and more complex control factors than sandstone reservoirs. Taking the Binxian Uplift area in the Boahi Bay Basin as an example, the aim of this study is to clarify the characteristics and control factors of the alluvial glutenite reservoir quality and the influence of reservoir properties on hydrocarbon accumulation. Pore types in the study area mainly include residual intergranular pores, intergranular dissolved pores, intragranular dissolved pores, and mold pores. The residual intergranular pores and intergranular dissolved pores are the main pore types. Most samples have porosity greater than 15% and permeability is mainly concentrated between 50 mD and 500 mD. It is shown that lithology type, microfacies, and diagenesis have significant impact on the reservoir quality. The reservoir qualities of very fine sandstone and fine sandstone are better than those of conglomerate and gravel-bearing sandstone. Instead of grain size, sorting affects the alluvial glutenite reservoir quality significantly. Oil-bearing samples commonly have sorting coefficient less than 2 while non-oil-bearing samples have sorting coefficient larger than 2. There are significant differences in reservoir physical properties of different sedimentary microfacies. The stream flow in mid-alluvial fan (SFMA) and braided channels outside alluvial fans (BCOA) have relatively weaker compaction and better reservoir quality than the overflow sand body (OFSB) and debris-flow in proximal alluvial fan (DFPA). Calcite cementation, the main cement in the study area, commonly developed at the base of SFMA and BCOA and near the sandstone-mudrock contacts. The source of calcium carbonate for calcite cement mainly came from around mudstone. High calcite cement content commonly results in low porosity and permeability. Individual glutenite thickness is also an important influencing factor on reservoir quality. Reservoirs with large thickness (>4 m) have high porosity and permeability. Dissolution occurred in the reservoir, forming secondary dissolution pores and improving reservoir quality. The dissolution fluid for formation of secondary pores is mainly meteoric waters instead of organic acid. The reservoir property has an important influence on hydrocarbon accumulation. The lower limit of physical properties of an effective reservoir is a porosity of 27% and permeability of 225 mD. The findings of this study can be utilized to predict the reservoir quality of alluvial glutenite reservoirs effectively in the Bohai Bay Basin and other similar basins.