Diagenesis of the Triassic Yanchang Formation Tight Sandstone Reservoir in the Xifeng–Ansai Area of Ordos Basin and its Porosity Evolution

This work aims to reveal the evolution of the porosity in the Triassic Yanchang Formation tight sandstone reservoir of the Xifeng-Ansai area of Ordos Basin. Based on destructive diagenesis （compaction and cementation） and constructive diagenesis （dissolution） of sandstone reservoirs, this study analyzed the diagenesis characteristics of the tight sandstone reservoirs in this area, and discussed the relationship between sandstone diagenesis and porosity evolution in combination with present porosity profile characteristics of sandstone reservoir. The effect simulation principle was employed for the mathematical derivation and simulation of the evolution of porosity in the Yanchang Formation tight sandstone reservoirs. The result shows that compaction always occurs in tight sandstone reservoirs in the Yanchang Formation, and cementation occurs when the burial depth increases to a certain value and remains ever since. Dissolution occurs only at a certain stage of the evolution with window features. In the corresponding present porosity profile, diagenesis is characterized by segmentation. From the shallow to the deep, compaction, compaction, cementation and dissolution, compaction and cementation occur successively. Therefore, the evolution of sandstone porosity can be divided into normal compaction section, acidification and incremental porosity section, and normal compaction section after dissolution. The results show that the evolution of sandstone porosity can be decomposed into porosity reduction model and porosity increase model. The superposition of the two models at the same depth in the three stages or in the same geological time can constitute the evolution simulation of the total porosity in sandstone reservoirs. By simulating the evolution of sandstone reservoir porosity of the eighth member in Xifeng area and the sixth member in Ansai area, it shows that they are similar in the evolution process and trend. The difference is caused by the regional uplift or subsidence and burial depth.

Quantification and timing of porosity evolution in tight sand gas reservoirs:an example from the Middle Jurassic Shaximiao Formation,western Sichuan,China

The diagenesis and porosity evolution of the Middle Jurassic Shaximiao sandstones were analyzed based on petrographic observations, X-ray diffractometry, scanning electron microscopy observations, carbon and oxygen stable isotope geochemistry, fluid inclusion mi- crothermometry, and thermal and burial history modeling results. The point count data show that secondary pores （av. 5.5 %） are more abundant than primary pores （av. 3.7 %） and are thus the dominant pore type in the Shaximiao sandstones. Analysis of porosity evolution indicates that alteration of sandstones mainly occurred during two paragenetic stages. Mechanical compaction and cementa- tion by early chlorite, calcite, and quartz typically decrease the depositional porosity （40.9 %） by an average of 37.2 %, leaving porosity of 3.7 % after stage I （〈85 ℃, 175-145 Ma）. The original intergranular porosity loss due to compaction is calculated to be 29.3 %, suggesting that mechanical compaction is the most significant diagenetic process in primary porosity destruction. Stage II can be further divided into two sub-stages （Stage IIa and Stage IIb）. Stage IIa （85-120 ℃, 145-125 Ma） is characterized by late dissolution, which enhanced porosity by 8.8 %, and the porosity increased from 3.7 % to 12.5 %. During stage IIb （〉120 ℃, 125-0 Ma）, the precipitation of late chlorite, calcite, quartz, and kaolinite destroyed 3.3 % porosity, leaving porosity of 9.2 % in the rock today.

Episodic dolomitization of Paleozoic limestones in the Kinta Valley,Malaysia:Implications on porosity evolution and reservoir properties

Carbonates undergo a variety of physical,mineralogical,chemical changes during depositional and postdepositional stages that are of interest to exploration geologists and sedimentologists.World over,about 60%of hydrocarbon reserves occur in carbonates with the dominant proportion associated with dolomitic reservoirs,in particular fault-associated dolomites which appear to be proven hydrocarbon reservoirs.Dolomitization as the critical diagenetic process thus plays an important role in determining reservoir characteristics and in designing exploration strategies.The buried Paleozoic dolomites exhibit relatively higher porosity than their counterparts,Paleozoic limestones.Fault-associated dolomites are usually targets of hydrocarbon exploration due to their good reservoir quality.High heterogeneity in carbonate reservoirs due to varied porosity types and distribution makes reservoir characterization a daunting task.However,the key elements that control porosity development and evolution in these dolomites remain debatable.Studying the influence of multiphase dolomitization,associated diagenetic events,hydrothermal alteration and their causative thermo-tectonic events on porosity evolution and reservoir quality is essential to understanding the critical processes and controlling factors that result in diverse impacts on reservoir quality.In this paper,an attempt is made to characterize dolomitization in homogeneous carbonate mud and its relationship with porosity evolution and reservoir property.In the field,six facies types excluding host limestone are recognized,which are in turn characterized into seven petrographically recognizable phases,namely the host limestone,early replacement dolomite,sucrosic dolomite,metamorphosed dolomite,late replacement dolomite,brecciated limestone and dolomite and late stage calcite.Mineralogical analyses reveal the dominance of stoichiometric dolomites,followed by calcareous dolomites and magnesium calcites.Among all the field-based facies and petrographic phases,the sucrosic dolomites show appreciable porosity within a range from 4%to 8%,whereas the other phases show either nil or insignificant porosity under megascopic and petrographic observations.Our study confirms that in the process of dolomitization that substantially modifies porosity,dolomitic crystal morphologies play a significant role in enhancing or reducing the porosity.

The nature, type, and origin of diagenetic uids and their control on the evolving porosity of the Lower Cambrian Xiaoerbulak Formation dolostone, northwestern Tarim Basin, China

The study on Lower Cambrian dolostones in Tarim Basin can improve our understanding of ancient and deeply buried carbonate reservoirs.In this research,diagenetic fluid characteristics and their control on porosity evolution have been revealed by studying the petrography and in situ geochemistry of different dolomites.Three types of diagenetic fluids were identified:(1) Replacive dolomites were deviated from shallow burial dolomitizing fluids,which might probably be concentrated ancient seawater at early stage.(2) Fine-to-medium crystalline,planar-e diamond pore-filling dolomites(Fd1) were likely slowly and sufficiently crystallized from deep-circulating crustal hydrothermal fluids during Devonian.(3) Coarse crystalline,non-planar-a saddle pore-filling dolomites(Fd2) might rapidly and insufficiently crystallize from magmatic hydrothermal fluids during Permian.Early dolomitizing fluids did not increase the porosity,but transformed the primary pores to dissolution pores through dolomitization.Deep-circulating crustal hydrothermal fluids significantly increased porosity in the early stages by dissolving and then slightly decreased the porosity in the late stage due to Fd1 precipitation.Magmatic hydrothermal fluids only precipitated the Fd2 dolomites and slightly decreased the porosity.In summary,Devonian deep-circulating crustal hydrothermal fluids dominated the porosity evolution of the Lower Cambrian dolostone reservoir in the Tarim Basin.

Simulation of coupled flowing-reaction-deformation with mass transfer in heap leaching processes

Governing equations for a fully coupled flowing-reaction-deformation behavior with mass transfer in heap leaching are developed. The model equations are solved using an explicit finite difference method under the conditions of invariable application rate and constant hydraulic head. The distribution of the degree of the saturation, as well as the distributions of the concentration of the reagent and the solute is given. A cubic relationship between the mineral recovery and the leaching duration is obtained based on the numerical results. The relationship can be used to predict the recovery percentage of the valuable metal.

Acid-base alternation diagenesis and its influence on shale reservoirs in the Permian Lucaogou Formation, Jimusar Sag, Junggar Basin, NW China

The diagenesis and diagenetic facies of shale reservoirs in Lucaogou Formation of Jimusar Sag were studied by means of microscopic observation and identification of ordinary thin sections and cast thin sections,X-ray diffraction,scanning electron microscope and electron probe tests.The results show that alkaline and acidic diagenetic processes occurred alternately during the deposition of Permian Lucaogou Formation in Jimusar Sag.The evolution of porosity in the shale reservoirs was influenced by compaction and alternate alkaline and acidic diagenetic processes jointly,and has gone through three stages,namely,stage of porosity reduction and increase caused by alkaline compaction,stage of porosity increase caused by acid dissolution,and stage of porosity increase and reduction caused by alkaline dissolution.Correspondingly,three secondary pore zones developed in Lucaogou Formation.The shale reservoirs are divided into three diagenetic facies:tuff residual intergranular pore-dissolution pore facies,tuff organic micrite dolomite mixed pore facies,and micrite alga-dolomite intercrystalline pore facies.With wide distribution,good pore structure and high oil content,the first two facies are diagenetic facies of favorable reservoirs in Lucaogou Formation.The research results provide a basis for better understanding and exploration and development of the Lucaogou Formation shale reservoirs.

Pore and fracture characteristics of Cretaceous tight reservoir and its control effect on hydrocarbon accumulation in the Liuhe Basin

Tight oil and gas in the Cretaceous has been found in the Liuhe Basin,but the rules of tight reservoir and oil and gas accumulation are not clear.This paper discusses the developmental characteristics and evolution law of pores and fractures in the Cretaceous tight reservoir in the Liuhe Basin,and reveals its controlling effect on tight oil and gas accumulation.The results show that intercrystalline pores,intergranular pores and dissolution pores are scattered and only developed in shallow tight reservoirs,while microfractures are developed in both shallow and deep layers,which are the main type of reservoir space in the study area.The results of mercury intrusion porosimetry and nitrogen gas adsorption show that with the increase of depth,the proportion of macropores(microcracks)increases,while the proportion of micropores decreases.There are two stages of microfractures developed in the study area,corresponding to the initial fault depression stage from late Jurassic to early late Cretaceous and compressional uplift at the end of late Cretaceous.According to the principle of“inversion and back-stripping method”,combined with the data of optical microscopy and inclusions,the time of each key diagenesis and its contribution to porosity are revealed,and the porosity evolution history of reservoirs in different diagenetic stages is quantitatively restored.The porosity reduction rate of compaction can reach more than 80%,which is the main reason for reservoir densification.The relationship between pore evolution history and oil and gas accumulation history reveals that during the oil and gas filling period of the Xiahuapidianzi Formation(90-85 Ma),the reservoir porosity is only 1.15%,but the development of microfractures in the first stage of the reservoir is conducive to oil and gas accumulation.

Restoration of formation processes of dolomite reservoirs based on laser U-Pb dating: A case study of Ordovician Majiagou Formation, Ordos Basin, NW China

To address the issue of non-unique interpretation of dolomite reservoir diagenetic and porosity evolution in the previous qualitative or semi-quantitative studies, we investigate two dolomite reservoir types, i.e. weathering-crust karstic reservoirs and mound-beach reservoirs, in the Ordovician Majiagou Formation, Ordos Basin by using in-situ laser ablation U-Pb dating as well as carbon and oxygen isotopic composition analysis. The results show that:(1) According to the dating of 8 reservoir samples, the Majiagou Formation experienced 5 diagenetic stages(Stage 1: deposition of matrix dolomite or penecontemporaneous dolomitization, in 444.0–494.0 Ma;Stage 2: dogtooth-or blade-shaped dolomite cementation, in 440.0–467.0 Ma;Stage 3: dolomitic silt filling, in 316.5–381.0 Ma;Stage 4: crystalline dolomite filling, in 354.0 Ma;Stage 5: crystalline calcite filling, in 292.7–319.0 Ma).(2) Supra-salt weathering-crust karstic dolomite reservoirs went through several diagenetic processes including penecontemporaneous dolomitization, compaction, weathering-crust karstification, packing, and rupturing in succession. Gypsum mold pores formed in the phase of hypergenic karstification and were filled with such minerals as dolomitic silts and calcites, and thus the porosity decreased from 10%–40% to 3%–8%.(3) Sub-salt mound-beach dolomite reservoirs went through the diagenetic processes including penecontemporaneous dolomitization, compaction, subsea cementation, penecontemporaneous corrosion, infiltration backflow dolomitization, packing, and rupturing. The porosity of reservoirs was originally 10%–30%, decreased to 0–6% due to seawater cementation, rose back to 5%–15% owing to penecontemporaneous corrosion, and finally declined to 2%–6% as a result of crystalline dolomites and calcites packing. The above methodology for the restoration of dolomitization and porosity evolution may be helpful for the restoration of porosity evolution in other basins or series of strata.

Slurry flow characteristics control of 3D printed ceramic core layered structure:Experiment and simulation

Vat photopolymerization 3D printing ceramic technology provides a feasible process for the preparation of complex internal cooling channels for aeroengine single crystal superalloy hollow blades.However,the typical layered structure characteristics of 3D printing ceramic technology led to the anisotropy of ceramic core strength and sintering shrinkage,which greatly affects the performance and accuracy of the complex structure core and requires further research and improvement.Herein,the influence of the thickness of the slurry layer on the flow characteristics of the slurry in the process of the vat photopolymerization 3D printing slurry spreading was systematically studied by the method of simulation and experiment.The simulation results show that the positions of the turbulent zone and maximum velocity zone in the scraper front affect the redistribution of powder particles with different sizes.The layered structure was caused by the redistribution of ceramic particles of different sizes in the slurry layer.By controlling the turbulent flow zone and the maximum velocity zone of the scraper leading edge,the phenomenon of laminar flow can be weakened and the particle redistribution can be improved.With the increase of the thickness of the printing layer,the layered structure appears gradually,and the pores at the interface of the layered structure gradually concentrated into the interfacial pore lines from the uniform distribution,and the crack propagation changes from intergranular micro-crack to interlayer macro-crack.The combination of finite element simulation and experiment,through the slurry flow characteristics to control the layered structure of reductive vat photopolymerization ceramic core 3D printing,the control of crack propagation mode,element distribution and pore evolution of the core was accomplished,which lays a foundation for the performance control of ceramic 3D printing technology.

Key Elements Controlling Oil Accumulation within the Tight Sandstones

Tight oil sandstone reservoirs with low porosity and permeability, which are an unconventional petroleum resource, have been discovered in the Jurassic intervals of the central Junggar Basin, the northwestern China. To reveal the accumulation mechanism, a relatively comprehensive research was conducted, including oil-source correlation, porosity evolution, and hydrocarbon charging history. The results show that crude oil of these tight sandstone reservoirs were mainly from Permian source rocks with some contribution from Jurassic source rocks. The reservoirs were buried at shallow depth（〈3 100 m） and exposed to weak diagenesis, and thus had high porosity（18.5%） when the Permian-sourced oil from Permian source rock was charging, indicating high GOI values（〉5%）. In contrast, the sandstone reservoir had already become tight and did not provide available space to accumulate oil due to severe compaction and cementation when hydrocarbon from Jurassic source rock filled, evidenced by low GOI values（〈5%）. Therefore, reservoir porosity controls the oil accumulation within tight sandstone. Whether tight sandstone reservoirs accumulate oil depends on the reservoir quality when hydrocarbons charge. Before the exploration of tight oil sandstone reservoirs, it should be required to investigate the relationship between oil charging history and porosity evolution to reduce the exploration risk and figure out the available targets.