Primary Intergranular Pores Research Articles

Pore structure evaluation in ultra-deep tight sandstones using NMR measurements and fractal analysis

The reservoir quality, pore spaces and pore size distributions of Bashijiqike sandstones in Kuqa depression were described by thin sections, SEM (scanning electron microscopy) analysis and nuclear magnetic resonance (NMR) tests. In order to quantitatively characterize the complexity of pore structure, NMR T2 (transverse relaxation time) spectrum was used for fractal analysis. This study unravels the relationships between petrophysical parameters, NMR parameters and fractal dimension of the ultra-deep tight sandstones. Primary intergranular pores are the main component of pore spaces, followed by secondary dissolution pores and micropores, and there contain microfractures. The NMR T2 spectra are either bi-modal or uni-modal distribution. The uni-modal T2 spectrum reflects uniform pore spaces. The coexistence of intragranular pores and intergranular pores leads to the bi-modal T2 spectrum. There is a positive correlation between fractal dimensions and T2gm (geometric mean of the T2 distribution). Consequently, four pore structure types are determined according to irreducible water content, T2gm, RQI (reservoir quality index), and the characteristics of individual pore structure are summarized. Because of the uniform pore space, Type I and Type IV have the lowest fractal dimensions. The structure of Type II and Type III are most heterogeneous due to their combination of intergranular and intragranular pores. The results help clarify the internal relationships between petrophysical parameters and microstructure, and have implications for pore structure evaluation of ultra-deep sandstones worldwide.

Structural controls on sandstone compaction within the anticline crest and flank: An example from the Xihu Sag, East China Sea Basin

The tight sandstones of the fourth (E3h4) and fifth (E3h5) members of the Oligocene Huagang (E3h) Formation in the Xihu Sag of the East China Sea Basin are feldspar lithic quartzose, which are ideal for the investigation of compaction. Based on routine core analysis, petrology, fluid inclusions, and compaction numerical simulation, this study investigated the compaction characteristics, porosity evolution, and high-value porosity area of tight sandstone on a structural anticline two-dimensional (2D) profile. The textural characteristics of the sandstones are moderately well sorted and are generally subangular-subrounded. The E3h4 and E3h5 sandstones on the crest of the anticline develop primary intergranular pores, whereas these sandstones on the flank develop a small amount of primary intergranular pores. The contact types between quartz grains on the anticline crest were mainly tangential, long, and concavo-convex contacts, whereas the contact types between quartz grains on the flank were primarily long, concavo-convex, and sutured contacts. The duration age of the mechanical compaction (MEC) porosity loss of sandy conglomerate (SC), fine-grained sandstone (FS), and medium-grained sandstone (MS) in the E3h4 and E3h5 members ranged from 27 Ma to 7 Ma. The onset of the chemical compaction (CHC) of the E3h4 and E3h5 sandstones were between 10.2 Ma and 10.6 Ma, respectively. Based on similar grain size, mineral composition, and sorting, the degree of the MEC of the E3h4 and E3h5 sandstones on the crest of the anticline is less than that of the flank due to burial depth. The distribution ranges of the MEC porosity loss were 21.92%–26.02% and 22.31%–26.43% for the E3h4 on the anticline crest and flank and 26.74%–27.26% for the E3h5 on the flank, respectively. By integrating similar burial time and clay minerals, the degree of the CHC of the E3h4 and E3h5 sandstones on the crest of the anticline is less than that of the flank due to reservoir temperature. The distribution ranges of the CHC porosity loss were 0.41%–1.05% and 0.44%–1.02% for the E3h4 on the anticline crest and flank and 0.48%–0.91% for the E3h5 on the flank, respectively. During the Late Miocene Longjing movement, the CHC porosity loss ranged from 0.15% to 0.4%. The study results show that the sandstone with porosity between 9% and 11% is distributed sporadically in E3h4 and E3h5, whereas the sandstone with porosity between 6% and 9% is distributed in contiguous pieces. The formation of high-value porosity areas is mainly due to the coarser grain size, shallower burial depth, chlorite coat, underdeveloped illite, lower reservoir temperature, and slight overpressure.

Characteristics of heterogeneous diagenesis and modification to physical properties of Upper Paleozoic tight gas reservoir in eastern Ordos Basin

To correctly evaluate reservoir quality and determine promising tight gas zones, the characteristics of heterogeneous diagenesis and modifications to physical properties in the Upper Paleozoic tight gas reservoir in the eastern Ordos Basin (UPTGREOB) were assessed by comprehensively analyzing lithology, petrophysics, and organic geochemistry data. It was found that the types of sandstones in UPTGREOB mainly include (feldspathic) detritus sandstones and detritus feldspathic sandstone in low–ultralow porosity and permeability, with complex pore structure. Sandstone pores can be divided into two types: primary (primary intergranular and residual primary intergranular pores), secondary (intercrystalline, dissolved intragranular, dissolved intergranular, and dissolved cementing pores and microfractures). The main types of diagenesis are compaction, cementation, dissolution, and metasomatic alteration. Shiqianfeng Formation and Upper Shihezi Formation belong to period B of the syndiagenesis stage and period A1 and A2 of the mesodiagenesis stage; Lower Shihezi Formation and Shanxi Formation are entirely in the mesodiagenesis stage; Taiyuan Formation can be regarded to be in periods A2 and B of the mesodiagenesis stage and period A of the telodiagenesis stage. The original porosity of UPTGREOB was approximately 34%. Compaction was the primary destructive diagenesis rather than cementation, while dissolution was found to be the primary constructive diagenesis. The heterogeneous diagenesis played different roles in the UPTGREOB: in syndiagenesis B, the UPTGREOB began to densify under the compaction and early cementation; in mesodiagenesis A, dissolution and metasomatic alteration produced massive secondary dissolved pores and intercrystalline pores, improving the porosity and permeability; in mesodiagenesis B, dissolved pores were filled by new cements, resulting in decreased porosity and permeability; in telodiagenesis A, intensified compaction and cementation made the UPTGREOB retain extra low porosity and permeability. In general, the reservoirs of Shiqianfeng Formation and Upper/Lower Shihezi Formation in the mesodiagenesis stage A have preferable physical properties for tight gas accumulation.

Testing origin of reservoir quality difference of tight sandstones in the Yanchang Formation, Ordos Basin, China

The Chang 7 and Chang 8 members of the Upper Triassic Yanchang formation are high-yielding tight sandstone oil reservoirs deposited in different sedimentary environments in the Ordos Basin. Lacustrine sediments are dominant in Chang 7 members, while delta front sediments are dominant in Chang 8 members. The causes of reservoir quality differences in the different sedimentary environments are not clear, which renders tight-oil exploration and development difficult. In this study, X-ray diffraction analysis (XRD), optical microscopy, scanning electron microscope (SEM), mercury injection tests and oil-water relative permeability tests were used to study the origin of reservoir quality differences between the Chang 7 and 8 reservoirs. The results show the following: 1) the Chang 8 and Chang 7 reservoirs are dominated by primary intergranular pores and dissolution pores, respectively. 2) Grain-coating chlorite is present in the Chang 8 reservoir, which is known to enhance the ability of reservoirs to resist compaction and prevent the growth of quartz. However, the reservoir pore space could be preserved only when the abundance of grain-coating chlorite is below the threshold of 4 vol%. 3) Carbonate cementation occurs pore-throat spaces, and the porosity of the reservoir tends to improve with carbonate content increase in the range of 0–10 vol%. This phenomenon is caused by carbonate minerals formed in different times. 4) The strong heterogeneity of pore sizes is the reason for rapid rise of capillary force of pore mercury saturation curve in Chang 8 reservoir. The throat volume controls the mercury saturation of the pore throats. The Chang 8 reservoir exhibit larger throat volume and higher permeability than Chang 7 reservoir. 5) The Chang 7 reservoir has small pore radius and poor connectivity. Therefore, it is difficult for water to displace the oil phase. As a result, the water phase permeability increases rapidly, the residual oil saturation is high, and the water productivity of the reservoir increases rapidly. In conclusion, the reservoir quality of Chang 8 Member is better than that of Chang 7 Member, and this can be attributed to the following factors: i) Chang 8 reservoirs have larger grain sizes and more abundant grain-coating chlorite, ii) the low content of illite and carbonate cement reduces reservoir cementation capacity and iii) the pore connectivity is better, because the throat radius and effective throat volume are larger. The results provide guidance for the efficient development of tight oil in these reservoirs.

Response to the Variation of Clay Minerals During ASP Flooding in the Saertu Oilfield in the Songliao Basin

In this paper, the variation of clay minerals and their influence on reservoir physical properties and residual oil before and after ASP flooding are analyzed. The results show that the total amount of clay minerals in reservoirs decreases after ASP flooding in the ultra-high-water-cut-stage reservoirs of the Naner Zone in the Saertu Oilfield, Songliao Basin. Therein, the illite content reduces, while the content of illite smectite mixed-layer and chlorite increases. The content of kaolinite varies greatly. The content of kaolinite decreases in some samples, while it increases in other samples. The clay minerals block the pore throat after ASP flooding. As a result, the pore structure coefficient and the seepage tortuosity increase, the primary intergranular pore throat shrinks, and the pore–throat coordination number decreases. Nevertheless, the dissolution of clay minerals reduces the pore–throat ratio and increases porosity and permeability. The variation of clay minerals after ASP flooding not only intensifies the reservoir heterogeneity but also affects the formation and distribution of residual oil. The residual oil of the oil–clay mixed adsorption state is a newly formed residual oil type related to clay, which accounts for 44.2% of the total residual oil reserves, so it is the main occurrence form of the oil in reservoirs after ASP flooding. Therefore, the exploitation of this type of residual oil has great significance to enhance the oil recovery in ultra-high-water-cut-stage reservoirs.

Study on characteristics of tight oil reservoir in Ansai Area of Ordos Basin– take the Chang 6 section of Ordos Basin as an example

ABSTRACT In order to understand the exploration and development potential of tight oil in the oil field exploration and development stage, the reservoir characteristics of Chang 6 oil formation in Ansai area of Ordos Basin were studied. In this paper, the reservoir characteristics are studied by using aseries of experimental data, such as cast sheet, cathodoluminescence, electron probe, conventional mercury injection, constant rate mercury injection experiment, scanning electron microscope, etc. The results show that the lithologic characteristics of Chang 6 reservoir group in Ansai area are mainly feldspathic sandstone, accounting for 64.57%, followed by lithic feldspathic sandstone accounting for 31.36%, the sum of the two accounting for 95.93%. Pores are most developed in Ansai area, and the interstitial materials are mainly chlorite, kaolinite and illite. Primary intergranular pores are mainly developed in this area. Besides primary intergranular pores, there are also some feldspar dissolved pores in Ansai region. There are many laumontite dissolved pores in this region. The reservoir type in Ansai region is “low porosity and ultra low permeability”, but the Chang 6 member reservoir in Ansai region is very well characterized by “low porosity and ultra low permeability”.

Genesis of reservoir heterogeneity and its impacts on petroleum exploitation in beach-bar sandstone reservoirs: A case study from the Bohai Bay Basin, China

Reservoir characteristics of beach-bar sandstone reservoirs in the 2nd member of the Shahejie Formation in Banqiao Sag are studied by means of well logging interpretation, thin section observation and physical property analysis. Further, the influence of deposition, diagenesis and internal architecture interface on reservoir quality are quantitatively analyzed. On this basis, the geneses of reservoir heterogeneity of beach-bar sandstone reservoirs are summarized. The following results are obtained. (1) Primary pores, secondary pores and micro-fractures are the main types of reservoir space in the study area, and the primary intergranular pore is the main pore type; the microscopic heterogeneity of reservoirs is strong, and the physical properties of beach-bar reservoirs in different regions vary widely. (2) Tectonic-deposition, diagenesis and reservoir internal architecture work in unison to cause the heterogeneity of beach-bar reservoir quality in the 2nd member of the Shahejie Formation in Banqiao Sag; the locations and scales of beach-bar sand bodies are obviously different in different fault blocks in the study area, determining the macroscopic distribution of beach-bar reservoirs; differential diagenesis intensifies the degree of reservoir heterogeneity; the fine-grained argillaceous deposits between different architecture units of beach-bar reservoirs are critical to the quality of reservoirs. (3) The differential distribution of beach-bar reservoir quality parameters in the study area affects the spatial heterogeneity of reservoirs, which not only controls the original oil/gas distribution, but also has a significant influence on the effect of waterflooding and leads to the local enrichment of remaining oil.

Reservoir Characteristics and Main Controlling Factors of the Mesozoic Volcanic Rocks in the D Oilfield in Southern Gentle Slope Zone of the Laizhouwan Sag

The Mesozoic volcanic rocks are widely developed in the Bohai Bay basin. The D oilfield, located in the southeast of the Bohai Bay Basin, is a Cenozoic depression developed on the base of the Mesozoic. The types of the volcanic rocks are complex and the reservoir space is diverse. According to the characteristics of the volcanic reservoir, such as vertical multi-stage and strong heterogeneity, and based on the analysis of the volcanic core observation, thin section identification, logging data and seismic data, we analyzed the reservoir space type, physical property characteristics and reservoir physical property control factors of volcanic reservoir in the study area. The results show that the volcanic rocks in the study area are mainly volcanic breccia, andesite and tuff; the lithofacies types mainly include volcanic eruption facies, effusion facies and volcanic sedimentary facies, and the volcanic eruption facies is the most developed. Four types of volcanic reservoirs and 14 effective storage space types have been identified from the macroscopic and microscopic multi-scale, mainly intergranular pores, intergranular dissolution pores, intracrystalline pores, structural fractures and weathering dissolution fractures. Reservoir performance is mainly affected by lithology, lithofacies, tectonic activity and diagenesis. The primary pores in the upper part of exhalative and explosive facies are the most developed. Early cement filling is beneficial to the preservation of primary intergranular pore space and is an important prerequisite for the formation of secondary dissolution pores. Under the action of multi-stage tectonic movement and weathering leaching, the reservoir performance of volcanic rocks has been greatly improved, and the volcanic rocks with superimposed fractures and porosities are effective volcanic reservoirs.

The enrichment law of tight sandstone gas in member 2 of Xujiahe in Yingshan gas field, Sichuan Basin

The enrichment law of desserts in Xujiahe formation of Sichuan Basin has become the core problem of tight sandstone gas reservoir. In view of this problem, taking the member 2 of Xujiahe Formation in Yingshan area of Sichuan Basin as an example, the author analyzes the main factors of enrichment of natural gas through the analysis of the basic geological features of sedimentary environment, reservoir, hydrocarbon source, structure and reservoir formation, and then discusses enrichment mode of natural gas. The results show that the reservoir forming conditions of member 2 in Yingshan area are superior, and the widely covered source rocks are developed, and the source rocks have good hydrocarbon generation potential. The sand bodies in the delta front with thick layers are deposited in member 2 of Xujiahe, which is distributed in large area, which lays the foundation for the development of high-quality reservoirs. The reservoir space types are various, mainly mainly including primary intergranular pores, dissolution pores and micro fractures, and the reservoir has good physical properties. The accumulation of natural gas in Yingshan structure is the result of coupling of the following factors: the development of high-quality reservoir controls the distribution of natural gas; the structural background is conducive to the enrichment of natural gas; the good matching relationship between faults and traps controls the differential accumulation of natural gas in the reservoir.

Controlling factors of carbonate cement and its influence on oil-water distribution of the Neogene Shawan Formation in the northern Chepaizi area, Junggar Basin, NW China

The distribution of physical property of the Neogene Shawan Formation(N1s) in the north of Chepaizi area (Abbreviated as “Chebei area”) is characterized by “double peak”, which is mainly related to carbonate cements in the reservoirs. It is observed that the large amounts of early carbonate cements are present in thin sections, which are inhomogeneously filled in some primary intergranular pores and caused strong heterogeneity of the reservoir. On the basis of convent calculate of carbonate cement in core, AxioVision image analysis with multiple times and multiple fields of view was used to supplement the calculation of carbonate cement content, and the relative error compared with the core measurement result was −0.14, which effectively compensated for the lack of core measurement data points. The content of carbonate cement has been characterized by “higher in the north area and lower in the south area” on the plane. The carbonate cement is formed in closed diagenetic environment with good sealing ability and water body stagnated alternately. The closed diagenetic environment of the Shawan formation in Chebei area primed the environmental foundation for the growth of carbonate cements, and the abundant Ca2+ in the formation water primed the material foundation for the growth of carbonate cements. The difference in Ca2+ content in formation water determines the distribution difference of carbonate cements, and the diagenetic environment is the controlling factor for the development of carbonate cements. The complex oil-water distribution in the study area is principally related to the carbonate cementation. The super heavy oil with high viscosity cannot enter the low porosity and permeability reservoir with tough cementation, which is prone to the phenomenon of oil-water inversion.

Impact of Diagenesis on the Low Permeability Sandstone Reservoir: Case Study of the Lower Jurassic Reservoir in the Niudong Area, Northern Margin of Qaidam Basin

The Lower Jurassic reservoir in the Niudong area of the northern margin of Qaidam Basin is a typical low permeability sandstone reservoir and an important target for oil and gas exploration in the northern margin of the Qaidam Basin. In this paper, casting thin section analysis, scanning electron microscopy, X-ray diffraction, and stable isotope analysis among other methods were used to identify the diagenetic characteristics and evolution as well as the main factors influencing reservoir quality in the study area. The predominant types of sandstone in the study area are mainly feldspathic lithic sandstone and lithic arkose, followed by feldspathic sandstone and lithic sandstone. Reservoir porosity ranges from 0.01% to 19.5% (average of 9.9%), and permeability ranges from 0.01 to 32.4 mD (average of 3.8 mD). The reservoir exhibits robust heterogeneity and its quality is mainly influenced by diagenesis. The Lower Jurassic reservoir in the study area has undergone complex diagenesis and reached the middle diagenesis stage (A–B). The quantitative analysis of pore evolution showed that the porosity loss rate caused by compaction and cementation was 69.0% and 25.7% on average, and the porosity increase via dissolution was 4.8% on average. Compaction was the main cause of the reduction in the physical property of the reservoir in the study area, while cementation and dissolution were the main causes of reservoir heterogeneity. Cementation can reduce reservoir space by filling primary intergranular pores and secondary dissolved pores via cementation such as a calcite and illite/smectite mixed layer, whereas high cement content increased the compaction resistance of particles to preserve certain primary pores. δ13C and δ18O isotopes showed that the carbonate cement in the study area was the product of hydrocarbon generation by organic matter. The study area has conditions that are conductive to strong dissolution and mainly occur in feldspar dissolution, which produces a large number of secondary pores. It is important to improve the physical properties of the reservoir. Structurally, the Niudong area is a large nose uplift structure with developed fractures, which can be used as an effective oil and gas reservoir space and migration channel. In addition, the existence of fractures provides favorable conditions for the uninterrupted entry of acid fluid into the reservoir, promoting the occurrence of dissolution, and ultimately improves the physical properties of reservoirs, which is mainly manifested in improving the reservoir permeability.

Diagenesis and reservoir quality of deep-lacustrine sandy-debris-flow tight sandstones in Upper Triassic Yanchang Formation, Ordos Basin, China: Implications for reservoir heterogeneity and hydrocarbon accumulation

Tight sandstone in the Upper Triassic Yanchang Formation, Ordos Basin, contains large accumulations of hydrocarbon resources. This study presents an investigation of the deep-lacustrine sandy-debris-flow tight sandstones in the Yanchang Formation, based on petrographic, geochemical and petrophysical analysis. It reveals that reservoir heterogeneity and hydrocarbon accumulation of tight sandstones were affected by diagenetic alteration. These tight sandstones are dominantly lithic arkoses and feldspathic litharenites which are characterized by moderate to good sorting, fine to medium grain, subangular to subrounded and poor reservoir properties (average porosity and permeability are 10.5% and 1.23 mD, respectively). Significant diagenesis including compaction, feldspar dissolution and cementation by carbonate, quartz and authigenic clay have altered the studied tight sandstones. Compaction and carbonate cementation are the dominant destructive diagenetic processes. Carbonate cements are mainly developed at the edge of sandstone (distance to the sandstone-mudstone boundary mostly < 1 m) due to the limited transportation distance from adjacent mudstone. The relative high-quality reservoir intervals will preferentially develop in the middle of sandstone (distance to the sandstone-mudstone boundary mostly > 1 m). Feldspar dissolution has no significant impact on reservoir quality, as it results in pore space redistribution. There is little variation due to the primary intergranular pores being converted to dissolution pores and intercrystal micropores of authigenic clay. The lower level of compaction in the middle sandstone is due to cemented marginal sandstone. Moreover the preservation and redistribution of the pore space of the middle sandstones is generally due to carbonate cementation and feldspar dissolution. Different petrophysical properties between marginal and central sandstones lead to reservoir heterogeneity. Reservoir petrophysical properties display a positive correlation with oil-bearing capacity, which reveals that hydrocarbon accumulation can also be affected by reservoir property. Ultimately, tight sandstones with porosity >6%, permeability >0.1mD and thickness >2 m can be regarded as effective reservoirs in the Yanchang Formation. The results will contribute to the understanding of the origin of deep-lacustrine sandy-debris-flow tight sandstones reservoirs, which will enable further exploration for effective reservoirs in lacustrine sandy debrites across the globe, predominantly in those sharing the same geological features.

Reservoir geology of the Berea Sandstone (uppermost Devonian), eastern Kentucky

Berea reservoirs in eastern Kentucky are developed in tight siltstone and sandstone. Precision horizontal drilling provides access to thin ( 0.1 md, porosity is generally >10%. Cement in Berea samples includes quartz overgrowths, ferroan dolomite, siderite, pyrite, and kaolinite. In addition, these rocks were subject to varying degrees of intergranular compaction, quartz overgrowths, and secondary porosity formation (grain dissolution). In thin section, three pore types were encountered: (1) primary intergranular pores, (2) secondary moldic pores, and (3) microporosity. Intergranular porosity is most common. Mercury capillary injection tests show that moderate-permeability (0.02–0.2 md) Berea has pore size distributions of 1 to less than 0.1 μm, but mostly from 0.5 to 0.6 μm, which are commonly found in gas reservoirs. Higher-permeability samples (1.2–2.0 md) have pore-throat diameter distributions of 2 to >0.1 μm. The highest pore volumes (near 3.25%) have pore diameters of 1–2 μm, which is more characteristic of oil-producing reservoirs.

Reservoir characteristics of Chang 2 Member of Yanchang Formation in Area A, Ordos Basin

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.

Reservoir characteristics and control factors of Tongbomiao formation in Hongqi sag

Hongqi sag is located in the north of Beiehur depression in Hailar Basin, which is a secondary structural unit in the peripheral depression of Hailar Basin, with great exploration potential. Based on SEM, conventional thin sheet, cast thin sheet, mercury pressure and physical property data, this paper discusses the reservoir characteristics, types and control factors of high quality reservoir in Tongbomiao formation, Hongqi sag, so as to provide a strong geological basis for the exploration of oil and gas in this area. The reservoir space of Hongqi sag is mainly composed of four types: primary intergranular pore, micro fracture, feldspar dissolution pore and debris dissolution pore. It is of the type of ultra low porosity and low permeability. Although Tongbomiao formation in Hongqi sag is of very low porosity and low permeability type, high quality reservoir is still developed, and its reason is mainly controlled by sedimentary environment, diagenesis and structural fracture.

Provenance, clastic composition and their impact on diagenesis: A case study of the Oligocene sandstone in the Xihu sag, East China Sea Basin

Sandstone composition, heavy mineral analysis, and bulk rock geochemistry analyses were used to investigate the provenance lithotypes and sediment transport pathways of the third, fourth, and fifth (E3h3, E3h4 and E3h5) members of the E3h Formation at the gas–reservoir scale in the Xihu sag, East China Sea Basin. In addition, the diagenetic features and porosity of the metamorphic-sourced and volcanic-sourced sandstones were investigated. The provenance lithotypes of the E3h3, E3h4, and E3h5 were mainly medium–low grade metamorphic rocks and felsic to intermediate volcanic rocks. The sediment transport pathways were from northeast to southwest and from east to west, indicating that the E3h3, E3h4 and E3h5 members had two sediment provenance, namely, the metamorphic rocks of the northern Hupijiao Rise and the volcanic rocks of the eastern Diaoyudao Rise. Then the sedimentary microfacies distribution of the E3h3, E3h4, and E3h5 members and its relationship with the dual provenance sedimentary system were determined by using the heavy mineral assemblages, ZTR index, grain sizes, lithic fragments and quartz content. The initial porosity values of the metamorphic-sourced medium-grained and fine-grained sandstones were 35.35% and 35.22%, respectively; while the initial porosity values of the volcanic-sourced medium-grained and fine-grained sandstones were 34.09% and 34.97%, respectively. The average porosity compaction loss percentages were mainly 80.2% and 86.91% for the metamorphic-sourced medium–grained and fine–grained sandstones, and 86.95% and 87.23% for the volcanic-sourced medium–grained and fine–grained sandstones. The contact types of mineral grains in the metamorphic-sourced sandstones were mainly punctual, linear and concave-convex contacts; while the contact types of mineral grains in the volcanic-sourced sandstones were mainly linear, concave-convex, and sutured contacts. The metamorphic-sourced sandstone mainly developed chlorite coats; while the volcanic-sourced sandstones mainly contained pore-filling chlorite. The average quartz cement contents were 0.83% and 0.61% for the metamorphic-sourced medium–grained and fine–grained sandstones, and 0.67% and 0.43% for the volcanic-sourced medium–grained and fine–grained sandstones. The illite, mixed-layer illite/smectite and calcite cement reduced the sandstone porosity by filling pores. The metamorphic–sourced sandstones mainly developed primary intergranular pores and intergranular dissolved pores; while the volcanic–sourced sandstones mainly developed intergranular dissolved pores, intragranular dissolved pores, and moldic pores. The metamorphic-sourced sandstones had a higher porosity than the volcanic-sourced sandstones with the same grain size, which the difference in their porosities reached 1–3%.

Diagenetic alteration, pore-throat network, and reservoir quality of tight gas sandstone reservoirs: A case study of the upper Paleozoic sequence in the northern Tianhuan depression in the Ordos Basin, China

The Sulige gas field in the Ordos Basin is the largest gas field in China. The studied area, the northern Tianhuan depression, is located west of the gas field and is considered as a potential gas-producing area. The complex diagenetic alteration history and its effects on the pore-throat network and reservoir quality of the tight gas sandstones are explained. The upper Paleozoic first member of the Shanxi Formation and eighth member of the Shihezi Formation tight gas reservoir rocks are composed of coarse- to medium-grained sandstones and are dominated by sublitharenites. The most important diagenetic factor for porosity reduction was compaction, followed by cementation. Diagenetic mineral phases include quartz overgrowth, calcite cement and replacement, and kaolinite cement and replacement, with minor heulandite and chlorite. Pressure dissolution of quartz grains and quartzite fragments is the main source of silica for the early and late quartz overgrowth cementation (formed mainly from 120°C to 140°C). The hydrolysis and alteration of volcanic material and mica flakes released some silicon, calcium, and aluminum ions. Calcium and carbon in calcite cements could be derived from surrounding mudstones. Calcite replaced the quartz overgrowths. The formation of kaolinite, as cement and replacements, was controlled by the interactions of silica, aluminum, pH, and temperature (140°C). Because of deformation of detrital components (mica flakes and ductile rock fragments) and diagenetic replacement, clear negative correlations between reservoir quality and contents of the diagenetic minerals are lacking. A complex and isolated pore-throat network was created by strong diagenetic transformation. Based on analysis of thin sections, three-dimensional x-ray micro–computed tomography, and constant-rate mercury injection data, the samples with relatively good reservoir quality (porosity >10% and permeability >0.5 md) are characterized by dissolution pores and primary intergranular pores and commonly contain more and larger pore throats both in volume (counts >1800 and size >0.02 per unit volume) and diameter (>1.20 μm) than the samples with poor reservoir quality. The intercrystalline pores of kaolinite are very widespread and considered favorable for oil and gas accumulation because some asphalt was found within these pores. This study may be used, by analogy, to better understand diagenetic factors controlling the formation of tight gas sandstone reservoirs and predict the development of pore-throat systems.

Analysis of pore throat characteristics of tight sandstone reservoirs

Abstract The characterization of pore throat structure in tight reservoirs is the basis for the effective development of tight oil. In order to effectively characterize the pore -throat structure of tight sandstone in E Basin, China, this study used high-pressure mercury intrusion (HPMI) testing technology and thin section (TS) technology to jointly explore the characteristics of tight oil pore throat structure. The results of the TS test show that there are many types of pores in the tight sandstone, mainly the primary intergranular pores, dissolved pores, and microfractures. Based on the pore throat parameters obtained by HPMI experiments, the pore throat radius of tight sandstone is between 0.0035 and 2.6158 µm. There are two peaks in the pore throat distribution curve, indicating that the tight sandstone contains at least two types of pores. This is consistent with the results of the TS experiments. In addition, based on the fractal theory and obtained capillary pressure curve by HPMI experiments, the fractal characteristics of tight sandstone pore throat are quantitatively characterized. The results show that the tight sandstones in E Basin have piecewise fractal (multifractal) features. The segmentation fractal feature occurs at a pore throat radius of approximately 0.06 µm. Therefore, according to the fractal characteristics, the tight sandstone pore throat of the study block is divided into macropores (pore throat radius &gt; 0.06 µm) and micropores (pore throat radius &lt; 0.06 µm). The fractal dimension D L of the macropores is larger than the fractal dimension D S of the micropores, indicating that the surface of the macropores is rough and the pores are irregular. This study cannot only provide certain support for characterizing the size of tight oil pore throat, but also plays an inspiring role in understanding the tight pore structure of tight sandstone.

Investigation of pore-type heterogeneity and its control on microscopic remaining oil distribution in deeply buried marine clastic reservoirs

Pore-type heterogeneity is a key factor controlling the distribution of microscopic remaining oil in clastic reservoirs. It is important to quantify the characteristics of pore-type heterogeneity, understand its formation mechanisms, and analyze its impact on remaining oil at microscopic scale. Here we addressed these issues by adopting a new characterization method of flow zone indicator (FZI) with conventional velocity data as input and pore aspect ratio (α) as intermediate parameter, and conducting CT scan imaging on reservoir samples with different pore types, as identified by FZI, at different levels of water injection. The results demonstrate that this method can effectively discern pore-type changes and characterize the variabilities of velocity and permeability. A value of FZI>2.1 is characteristic of lithic quartzarenite with large amount of residual primary intergranular pores, which developed mainly in a shoreface environment. Clay rim cementation prevails in this reservoir type, as it can survive compaction, inhibit quartz overgrowth, and thus preserve intergranular pores with large pore-throat radius and good connectivity. The displacement pressure of this reservoir type is low during water flooding and the water swept area is wide; as a result, the majority of clustered flows are displaced and the remaining oil is present small patches in the form of multiporous flow. Samples with FZI<1.5 represent litharenite with large amount of intragranular dissolved pores, which developed mainly in foreshore and offshore-transition zone facies. This reservoir type underwent intense compaction and dissolution, which resulted in small pore-throat radius, poor connectivity and high displacement pressure. The injected water flows along the preferential pathways with relatively small flow resistance in this reservoir type during oil displacement such that the water swept area is limited; therefore the remaining oil is present continuous characteristics in the form of clustered flow. A transition zone with 1.5 < FZI<2.1 exists between the upper two reservoir types; this contains mixed lithologies and pore types, and exhibits medium pore-throat radius, connectivity and displacement pressure. The remaining oil in this reservoir type is present in the form of clustered flow and a small amount of multiporous flow, displaying continuous characteristics or small patches. Moreover, the water displacement process mainly occurs in relatively large pore-throats, which make a major contribution to permeability in each reservoir type. The heterogeneity of these pore-throats, as indicated by fractal dimension, controls the final oil displacement efficiency. The results of this study can be broadly applied to the characterization of similar clastic reservoirs and for further research in multi-scale heterogeneity.

Reservoirs properties of slump-type sub-lacustrine fans and their main control factors in first member of Paleogene Shahejie Formation in Binhai area, Bohai Bay Basin, China

Abstract High-yielding oil wells were recently found in the first member of Paleogene Shahejie Formation, the Binhai area of Qikou Sag, providing an example of medium- and deep-buried high-quality reservoirs in the central part of a faulted lacustrine basin. By using data of cores, cast thin sections, scanning electron microscope and physical property tests, the sedimentary facies, physical properties and main control factors of the high-quality reservoirs were analyzed. The reservoirs are identified as deposits of slump-type sub-lacustrine fans, which are marked by muddy fragments, slump deformation structure and Bouma sequences in sandstones. They present mostly medium porosity and low permeability, and slightly medium porosity and high permeability. They have primary intergranular pores, intergranular and intragranular dissolution pores in feldspar and detritus grains, and structural microcracks as storage space. The main factors controlling the high quality reservoirs are as follows: (1) Favorable sedimentary microfacies of main and proximal distributary gravity flow channels. The microfacies with coarse sediment were dominated by transportation and deposition of sandy debris flow, and the effect of deposition on reservoir properties decreases with the increase of depth. (2) Medium texture maturity. It is shown by medium-sorted sandstones that were formed by beach bar sediment collapsing and redepositing, and was good for the formation of the primary intergranular pores. (3) High content of intermediate-acid volcanic rock detritus. The reservoir sandstone has high content of detritus of various components, especially intermediate-acid volcanic rock detritus, which is good for the formation of dissolution pores. (4) Organic acid corrosion. It was attributed to hydrocarbon maturity during mesodiagenetic A substage. (5) Early-forming and long lasting overpressure. A large-scale overpressure compartment was caused by under-compaction and hydrocarbon generation pressurization related to thick deep-lacustrine mudstone, and is responsible for the preservation of abundant primary pores. (6) Regional transtensional tectonic action. It resulted in the structural microcracks.