Preservation Of Primary Pores Research Articles

Variations of sedimentary environment under cyclical aridification and impacts on eodiagenesis of tight sandstones from the late Middle Jurassic Shaximiao Formation in Central Sichuan Basin

Understanding eodiagenesis is essential to decoding the diagenetic pathways of tight sandstones that act as excellent unconventional oil & gas reservoirs. Great paleoclimate change is capable of influencing eodiagenetic processes of tight sandstones through variations of sedimentary environment. However, it is less noted how climate gradients between the greenhouse and the hothouse conditions impact the eodiagenesis of tight sandstones. We examined eodiagenetic processes that has been operated in the Shaximiao Formation sandstones using petrographic observation, scanning electron microscopy, geochemistry, and XRD analysis to reveal impacts of the transitional climate changes on the differential eodiagenesis and implications for the diagenesis-porosity evolution. Based on sequence stratigraphy, the Shaximiao Formation is divided into four sub-members SXM1, SXM2, SXM3, and SXM4, respectively. Dark sandstones and mudstones mainly occurred in the SXM1 and the SXM2. Grey-green clastic rocks are dominant in the SXM3, whereas red mudstones frequently appear in the SXM4. Paleoclimate indices denote that a cyclical aridification from the warm-humid to hot-semiarid conditions took place from the SXM1 to the SXM4. It could have been caused by the megamonsoon effect and the paleogeographic shift along with the breakup of the Pangaea supercontinent. Combined with the migration of depocenters, the paleoclimate change resulted in transformation of sediment provenances from mafic igneous rocks to quartzose sedimentary rock along with the decreasing textural maturity. Therefore, sedimentary environments varied from the high-saline to low-saline and from low-oxygen to high-oxygen conditions respectively, which had a crucial impact on eodiagenetic cements which were formed in the Shaximiao Formation. Chlorite and laumontite cement precipitation was promoted by high-saline alkaline fluids. Chlorite proportions show an arched trend from the SXM1 to the SXM4, compatible with those of primary and secondary porosities. In contrast, laumontite proportions exhibit a decreasing variation from the SXM1 to the SXM4. High percentages of early cements are favorable to improving resistance to the compaction and preservation of primary pores. However, high chlorite (>5%) and laumontite (>10%) proportions are destructive for the reservoir quality. Large quantities of laumontite cements occupy primary pores and impede diagenetic fluids flowing and are not favorable to the dissolution. By contrast, an excess of chlorite cements can be dissolved to produce secondary pores during the organic acid release. Thus, the SXM2 is potential as a reservoir for oil & gas. Therefore, those eodiagenetic cements can control the late diagenetic evolution and the reservoir quality. Observations made here have implications for understanding tight sandstone reservoirs elsewhere in the world.

Study on factors affecting the petro physical properties of sandstone and conglomerate reservoirs of Baikouquan Formation, Junggar Basin

In recent years, oil and gas exploration of the Baikouquan Formation in the northwestern margin of the Junggar Basin has seen major breakthroughs have been made in oil and gas exploration. Sandstone and conglomerate reservoirs are developed in the Baikouquan Formation in this area, but the factors affecting the differences in petro physical properties of these two types of reservoirs are still unclear. In this paper, taking the Baikouquan Formation in the Hongcheguai area on the northwestern margin of the Junggar Basin as an example, a large number of core observations, thin sections, scanning electron microscopy, and petro physical property test data were used to evaluate the petro logical characteristics, reservoir space types, digenesis and pore evolution of the sandstone and conglomerate reservoirs. The results show that the sandstone and conglomerate rocks of the Baikouquan Formation in the study area have a large content of tuffaceous components. The sandstone reservoirs are dominated by primary intergranular pores, and the conglomerate reservoirs are dominated by secondary dissolved pores. In addition, the porosity is negatively correlated with rock permeability for the conglomerate rocks of the Baikouquan Formation. However, the porosity is positively correlated with rock permeability of the sandstone reservoirs. According to the analysis of the digenetic process, the compaction and cementation can lead to a significant decrease in the petro physical properties of the reservoir. While dissolution can improve the petro physical properties of the sandstone reservoirs to a small extent, and can improve that of the conglomerate reservoirs to a greater extent. Moreover, local fractures are important factors affecting the petro physical properties of the conglomerate reservoirs. The existence of abnormal high pressure has a certain effect on the preservation of primary pores. On the whole, the controlling factors of the petro physical properties of the conglomerate reservoirs in the Baikouquan Formation include sedimentation, diagenesis, and tectonic actives, while that of the sandstone reservoirs mainly include sedimentation and diagenesis.

Simulation experiment of fluid-feldspar sandstone interactions and their implications for tight oil and gas exploration of the Yanchang Formation, Ordos Basin, China

Tight oil and gas reservoirs are generally formed in structurally stable and broad buffer zones, with high-quality source rocks developed in large areas and sand bodies in extensive contact with source rocks. Fluids generated from source rock during the thermal maturation are bound to dissolve or precipitate in the adjacent reservoir, which directly restricts the pore development of the reservoir and the direction of oil and gas exploration. To reveal the effect of the total component fluids from source rock on reservoir transformation during hydrocarbon evolution, taking the Yanchang Formation of the Ordos Basin as an example, a fluid-feldspar sandstone interaction simulation experiment of different geological evolution stages under a closed environment was carried out. The results show that the fluids that formed in the hydrocarbon evolution process contain organic acids, and consist mainly of acetic acid. At the peak period of oil generation (VRo = 0.96%), the fluids are the most acidic, the acetic acid yield is the highest, and the average molar ratio is 56.11%. Under closed conditions, after the fluid-feldspar sandstone interaction, the feldspar minerals are altered and clay minerals are generated in situ, which results in a tight reservoir. The feldspar mineral content decreased from 26.1% to 20.8%–22.3%, clay mineral content increased from 11% to 14.30%–14.37%, porosity decreased 5.18%–28.79%, and permeability decreased 4%–34.16%. In addition, a semi-quantitative evaluation method of feldspar dissolution and porosity was established, which was used to evaluate the effect of fluids on feldspar sandstone reservoirs during hydrocarbon evolution. The local semiclosed or open diagenetic system and acid fluid transport and accumulation area beneficial to the formation of the “sweet spot” of tight oil and gas. However, the gentle tectonic setting and extensive contact of sand and mudstone lead to the retention effect of diagenetic fluid in the Yanchang Formation of the Ordos Basin. Oil and gas exploration should be mainly directed to finding sedimentary sand facies bodies favorable for the formation and preservation of primary pores.

Physical simulation experiments on pore evolution in high-temperature and overpressure reservoirs

At present, simulation on reservoir evolution under normal pressure is common while that under abnormal pressure is rare. In this paper, the Miocene “high-temperature and overpressure” reservoir in the Ledong–Lingshui Sag of the Qiongdongnan Basin was taken as the research object to quantitatively define the effects of high pressure and overpressure on the evolution of reservoir pores. After the temperature and pressure field in this area was divided in the setting of sedimentation and diagenesis, the evolution characteristics of pores in different temperature and pressure field were analyzed by means of natural analogy and physical simulation experiment. Then, the effects of overpressure and fluids on the evolution of reservoir pores were discussed. Finally, the main factors controlling the development of high-quality reservoirs were determined. And the following research results were obtained. First, the temperature and pressure field of the Miocene reservoir in the Ledong–Lingshui Sag can be divided into three zones, i.e., high temperature and normal pressure zone, high temperature and overpressure zone, and high temperature and super overpressure zone. Second, overpressure and super overpressure can provide some preservation on primary pores. In the same diagenetic stage, the plane porosity of overpressure and super overpressure reservoirs is 1.23–6.74% higher than that of normal pressure reservoirs. Once the reservoir pressure in overpressure and super overpressure areas is higher than hydrostatic pressure by 8 MPa and 4 MPa, respectively, about 1% primary pores are preserved. Third, the dissolution of organic acid makes greater contribution to the secondary pores in reservoirs and its plane porosity is 0.96–7.38% higher than that of normal compaction reservoirs. Fourth, the leaching effect of meteorological water on reservoir physical properties is slight, and its plane porosity is only 0.19% higher than that of normal compaction reservoirs. In conclusion, the dissolution of organic acid is the most constructive effect for the reservoirs in high temperature and normal pressure. In addition, preservation of primary pores by overpressure is the most constructive effect for the reservoirs in high temperature and (super) overpressure, and the higher the overpressure is, the more preservation effect it provides on pores.

The effect of thermal maturity on porosity development in the Upper Devonian –Lower Mississippian Woodford Shale, Permian Basin, US: Insights into the role of silica nanospheres and microcrystalline quartz on porosity preservation

Organic-matter pores are considered to be the dominant contributor to total porosity in many shale reservoirs, and consequently much attention has been paid to investigate the factors influencing their generation, especially thermal maturity. Recent studies have shown that in addition to maturation of organic matter, other diagenetic processes also play important roles in evolution of pore systems, including compaction, mineral dissolution, and quartz cementation. This study investigates the effect of thermal maturity on porosity development in the siliceous Woodford Shale by integrating multiple techniques including helium pycnometry, low pressure gas (N2) adsorption, mercury injection capillary pressure, and field emission scanning electron microscopy (SEM) analyses. We compare samples from two long cores from Woodford Shale at different levels of thermal maturity, one in the early oil window (average calculated Ro = 0.69%) and the other in the wet gas window (average calculated Ro = 1.34%).Porosity, pore size, type, and volume vary systematically with the thermal maturity increasing from early oil window to wet gas window. Porosity measured by helium pycnometry averages 4.1% for early oil window samples, and increased by approximately 50% for the wet gas window samples (average porosity =6.3%). Both pore size and pore throat size distributions display decreasing trends from early oil window to wet gas window. Petrographic examination of SEM images shows that pores developed between clay platelets dominate in the early oil window samples, and secondary organic-matter pores are the dominant pore type in wet gas window samples. Porosity shows no obvious correlation to TOC content in both oil window and gas window samples, but correlates positive to silica content, suggesting that silica content largely controls variations in porosity. Both silica nanospheres and microcrystalline quartz were observed and appear to be significant in preserving pores from compaction by forming rigid frameworks that prevent pores from collapsing. Generation of secondary organic-matter pores and preservation of primary pores by silica nanospheres account for the net porosity increase from early oil window to wet gas window.

Paleogene geological framework and tectonic evolution of the central anticlinal zone in Lufeng 13 sag, Pearl River Mouth Basin

The Paleogene geological framework and evolution process in the central anticline zone in the Lufeng 13 sag in Pearl River Mouth Basin is well analyzed through seismic data and drilling data, and control of tectonic evolution on hydrocarbon accumulation is also discussed. The results show that the central anticline zone in the Lufeng 13 sag develops the upper deformation layer and lower deformation layer. The “arched graben system” is developed in the upper deformation layer, and the magmatic diapir structure and flowing deformation of plastic strata is developed in the lower deformation layer. The evolution process of the central anticline zone can be divided into four stages, i.e. fault block uplifting stage, prototype stage, strengthening stage and finalization stage. The geological framework and tectonic evolution of the central anticline zone control Paleogene hydrocarbon accumulation. The Paleogene two-layer geological framework is favorable for development of structural traps and composite traps; the paleostructure highs are the direction of hydrocarbon migration, and the gravitational gliding faults are the main carrier bed for vertical hydrocarbon migration; the tectonic uplift is a key factor for reservoir diagenesis improvement and preservation of primary pores, and also controls distribution of high-quality reservoirs.

Research Progress of Porosity in Microbial Carbonates

Microbial carbonates are not only important sedimentary records for paleo environments, paleoclimate and geological events, but also significant hydrocarbon reservoirs. Physiological characteristics of diverse microbial communities in part control the formation and preservation of primary pores, microbial depositional fabrics in various scales affect the diameter and distribution of pores. Combination patterns of microbial carbonates and associated facies have a great impact on usefulness and scale of pores. Different sedimentary processes and depositional environments of microbial carbonates affect sequences and degrees of cementation and dissolution during meteoric diagenesis, resulting in heterogeneity of pores. Microbe-related diageneses such as dolomitization, cementation, and karstification may form primary pores, protect residual pores and form secondary pores during various stages. Pore diameters of microbial carbonates are in range from nanometer-submicron level to centimeter and even meter level, which may correspond to multi-scale sedimentary structures to some extent. Therefore, it's necessary to analyze and characterize samples in various scales. In addition, the combination of geology and geophysics should be enhanced, being an important way to facilitate research of hydrocarbon reservoirs of microbial carbonates also benefit for the exploration and exploitation of oil and gas resources.

Comparison of basic features and origins of oolitic shoal reservoirs between carbonate platform interior and platform margin locations in the Lower Triassic Feixianguan Formation of the Sichuan Basin, southwest China

The oolitic shoal reservoirs of the Lower Triassic Feixianguan Formation carbonates in the Sichuan Basin of southwest China are an important target for gas exploration in the basin. Their occurrence, like other cases worldwide, can be divided into two locations in general, i.e., platform interior and platform margin locations. Their differences of reservoir features and origins, however, have not been investigated comprehensively due to different exploration degrees. This issue is addressed in this paper, to provide basic data and information for the basin’s hydrocarbon exploration and for the study of carbonate platform sedimentology and reservoir geology worldwide. We compared the features of these two types of reservoirs in detail, including the depositional and diagenetic features, pore types and petrophysical features. Based on the comparison, the origin of the reservoirs was further discussed. It is shown that the reservoirs in platform interior and platform margin locations differ significantly. The interior carbonates were deposited in moderate to high energy settings and the dominant lithologic type was limestone, which was weakly compacted and intensely cemented and has undergone meteoric dissolution. Pore types include intragranular dissolution and moldic pores, with low porosities ( 9% porosity and >0.1 mD permeability) and pore-throat structures than the interior reservoirs. These differences were influenced by both primary depositional features and secondary diagenesis. For the interior carbonate reservoirs, early meteoric dissolution, weak compaction and strong cementation are important controlling factors. By contrast, the factors controlling the formation of the margin carbonate reservoirs mainly include dolomitization, preservation of primary pores and burial dissolution.

Origin and controlling factors of chlorite coatings—an example from the reservoir of T3x Group of the Baojie area, Sichuan Basin, China

The study of the chlorite coatings always attracts scholars in China and other countries because the chlorite coatings play an important role in the preservation of residual primary pores in sandstone reservoirs. At present, the study of the origin and the controlling factors is relatively few. The occurrence, time of formation, genesis, controlling factors, and the mechanism of chlorite coatings inhibiting quartz overgrowths were studied in detail with thin section and SEM analysis. Samples were from the sandstone reservoirs of the T3x Group in the Baojie area, the transitional zone from the middle to the south of Sichuan Basin. The results indicate that the chlorite coatings on the walls of the pore spaces are oriented perpendicular to grain surfaces in the form of isopachous (even-thickness) grain-coating, while the chlorite coatings at the contacts between adjacent detrital grains are arranged with a preferred orientation tangential to the surface of detrital grains. The chlorite coatings were formed in the eogenetic stage. They were formed by recrystallization of Fe-rich clay films during the syndepositional period, and chlorite cements would be recrystallized after the coatings’ formation. The formation of chlorite coatings was mainly controlled by the depositional environment, provenance conditions, and diagenetic environment. The presence of chlorite coatings could result in the preservation of primary pores in deeply buried sandstone reservoirs by effectively inhibiting quartz overgrowths and the development of compaction and pressure solution.

Recognition and Contribution of Deep-Burial Diagenesis to Porosity Evolution in Carbonate Reservoir Rocks: ABSTRACT

Porosity and permeability develop in carbonate rocks by several processes, including preservation of primary pores, secondary pore formation as a result of dissolution of grains and cements, and dolomitization. Secondary porosity formation most commonly is postdepositional and occurs in environments from subaerial meteoroic (eogenetic) to deep burial, the latter involving fluids of meteoric, connate, or hydrothermal character. In the past, reservoir formation models have been dominated by analogy to studies of diagenesis and porosity occurrence in shallow meteoric environments. However, porosity occlusion and formation are amply documented in deep-burial diagenetic settings in ancient rocks, and such environments are known to exert predictable controls on the evolution of hydrocarbon reservoirs. Pore types created in such settings commonly mimic those in eogenetic environments to the extent that recognizing specific diagenetic environments of reservoir formation is not possible through the petrographic study of pore systems alone. Recognizing the deep-burial origin of porosity in hydrocarbon reservoirs can contribute much to predictions concerning possible porosity trends in the subsurface. Petrographic studies combined with comparative stable isotopic and trace element distributions in rock components are the most reliable means of tracing porosity evolution in deep burial diagenetic environments.