Brittle Minerals Research Articles

Shale gas potential of the Ranikot group, lower Indus basin, Pakistan

Natural gas production from tight and impermeable shale formations can be recognized as shale gas and has developed into a significant source of natural gas globally. With the development of modern technology, natural gas prices are likely to rise rapidly in response to substantial supply and demand pressures. The gross thickness of the Ranikot Group in the Lower Indus Basin ranges from 100 m to 400 m. The Ranikot Group is nearly 300 meters thick in the studied area having a depth of more than 1000 m to 2000 m. Geochemical studies indicate that the TOC content analyzed in specimens varies in range from 0.69-8.5 wt. % and the average value is about 2.30 wt%. Hydrogen Index ranges from 40-250 mg HC/g, hence, exhibiting the type III kerogen, which is also corroborated by the Van Krevelen diagram and shows a tendency to generate the gaseous hydrocarbons. The studied samples' Production Index (PI.) is between 0.02-26.2, averaging2.41 mg HC/g rock. Tmax varies from 420 to 444 oC, and Vitrinite Reflectance (R o) is between 0.4-0.8%, indicating that the organic matter in the shales of RaniKot Group is immature to early mature. In the studied shale intervals of the Ranikot Group, the clay (ductile mineral) content ranges from 20-30%, while brittle mineral content (quartz) ranges from 70-80%. High Brittleness Index, value (0.6 -Average), lesser values of Poison Raito, and higher values of Young's Modulus reveal that Ranikot Group's shales are within the brittle region. Studied samples of Ranikot Group were mostly brittle. Therefore, it is suggested that the formation is suitable for hydraulic fracturing.

Elastic properties and pore structure characterization of selected shales in the sungai Perlis beds, Terengganu, Peninsular Malaysia

Studied drill core of the Sungai Perlis Beds in the Terengganu State, Peninsular Malaysia, consists of a diverse suite of organic rich shale lithofacies at various subsurface depths. Lithofacies were delineated on the basis bedding thickness, mineralogy, and organic richness carried out by X-ray diffraction and (XRD) total organic content (TOC) analysis. Field-emission scanning electron microscopy (FE-SEM) analysis was carried out to identify the pore structure, range of pore sizes and mineral arrangement within each lithofacies unit Elastic geomechanical properties (Young’s modulus and Poisson’s ratio) were measured on core samples from each lithofacies unit using static and dynamic approaches. The identified lithofacies include moderate TOC massive argillaceous shale (MTOCMAS), high TOC massive argillaceous shale (HTOCMAS) and high TOC massive siliceous shale (HTOCMSS). FE-SEM analysis shows that pores in all the lithofacies are mostly intergranular, associated with phyllosilicate minerals, and ranges from <1 micrometer to approximately 8 micrometer. Static and dynamic elastic properties measurement shows that shale lithofacies having a high content of phyllosilicate minerals has a lower Young’s modulus and a high Poisson’s ratio value while lithofacies rich in brittle minerals has a higher Young’s modulus and a low Poisson’s ratio value. A good correlation exists between mineralogical brittleness index of the lithofacies and their plane strain modulus. The plane strain modulus is found higher in lithofacies having abundance of brittle minerals in the matrix suggesting that the high TOC massive siliceous shale (HTOCMSS) would preferably allow formation of dense hydraulic fractures, as observed in the CT scan analysis of triaxially fractured specimen, compared to argillaceous shale lithofacies.

Petrographic and geochemical characteristics of deep-lacustrine organic-rich mudstone and shale of the Upper Triassic Chang 7 member in the southern Ordos Basin, northern China: Implications for shale oil exploration

Organic-rich lacustrine mudstones and shales in Chang 7 member of the Upper Triassic Yanchang Formation are potential shale oil reservoirs. Petrographic and geochemical data were used to study their lithologic and geochemical characteristics, mineral composition and sedimentary environments. Three different types of deep lacustrine deposits are identified, including unstratified massive mudstone (muddy debrite), normally graded mudstone (muddy turbidite) and laminated shale. Mudstones and shales contain relatively abundant brittle minerals (quartz, feldspar, pyrite and carbonates), which are favorable for the hydraulic fracturing. Terrigenous input and diagenesis conversion process are the main sources of felsic minerals. Laminated shales yield the highest TOC values (average of 7.47%) as well as S1 and S2 values. Most of the mudstones and shales contain Type II organic matter, while contain little Type I organic matter. The Ro and Tmax values combined with OEP versus CPI and C29ββ/(ββ + αα)sterane versus αααC29sterane20S/(20S + 20R) discrimination diagrams and Ts/(Ts + Tm) ratios, indicate that the mudstones and shales are mature. Ph/C18 versus Pr/C17 and Pr/Ph versus gammacerane/C30-hopane discrimination diagrams together with U/Th, V/(V + Ni) and Ce/La ratios show that mudstones and shales reflect a reducing depositional environment. N-alkanes of ΣnC21-/ΣnC22 + values and C27-C29 regular sterane distributions suggest that plankton and terrestrial plants are the parent materials of organic matter. In addition, small amounts of extended homohopanes (>C31) and gammacerane combined with Sr/Ba values support a fresh water depositional environment. These conditions have resulted in high quality and widespread distribution of organic mudstones and shale, which are favorable for shale oil exploration.

Marine Shale Gas Occurrence and Its Influencing Factors: A Case Study from the Wufeng-Longmaxi Formation, Northwestern Guizhou, China

Organic-rich shales were found in the Ordovician to Silurian Wufeng-Longmaxi Formation in northwestern Guizhou province, China, which has high shale gas content revealed by field measurement. Shale gas occurrence, free gas/sorbed gas ratio, and their influencing factors are crucial for shale gas exploitation strategy. Results indicated that the Wufeng-Longmaxi shales are dominated by type I kerogen, with total organic carbon (TOC) and equivalent vitrinite reflectance (eqvRo) of 0.77%–6.98% and 2.37%–2.53%, respectively. The total porosity and permeability are in the range of 1.23%–8.43% and 3 × 10 − 4 – 2.23 × 10 − 1 mD, respectively. FE-SEM observation and correlation analysis show shale porosity is dominated by organic matter (OM) pores, followed by interparticle (interP) pores related to brittle minerals. CH4, derived from oil cracking, is the main component of shale gas, but its proportion is lower than that in Fuling and Weiyuan areas, probably due to the weak preservation condition. Desorption gas and lost gas determined by in situ desorption test are 0.42–1.54 cm3/g and 1.9–7.14 cm3/g, respectively, and Langmuir volume ( V L ) from isothermal adsorption experiment is 1.63–4.78 cm3/g. Shale gas content is positively correlated with micropore volume, mesopore volume and TOC content but negatively correlated with macropore volume and clay mineral content, indicating that methane is preferentially stored in micropores (&lt;2 nm) and mesopores (2–50 nm) related to OMs. By comparing actual total gas content with theoretical gas content, shale gas is considered to exist primarily in sorbed state, and the free gas proportion can increase with increased TOC content, due to that OM pores with larger sizes are also main space for free gas. Combined with the two methods, it can result in accurate calculations of shale gas reserves and free/sorbed gas ratio. Based on this understanding, a model of shale gas occurrence was proposed, which can provide a reference for shale gas exploitation in normal pressure areas.

Geological Characteristics and Controlling Factors of Enrichment of Deep Shale Gas in the East Weiyuan–North Rongchang Area, Sichuan Basin, China

The southern Sichuan Basin is the core area of China’s efficient development of deep shale gas (burial depth greater than 3,500 m). Reservoir geological characteristics determine whether shale gas can be preserved, enriched, and produced. Taking the Long 11 sub-member of the Wufeng Formation of the Upper Ordovician and the Longmaxi Formation of the Lower Silurian in the East Weiyuan–North Rongchang area as an example, we used the core, logging, production test, and other data, combining X-ray diffraction analysis, LECO Total Organic Carbon (TOC)-S analysis, optical microscopy, and argon ion polishing field-emission scanning electron microscopy, to study the shale mineral composition, geochemistry, reservoir space, pore structure characteristics, and reservoir physical properties. The following results were obtained: 1) The brittle mineral content, organic matter maturity, and TOC content are high, gradually increase from top to bottom, and reach their maxima at small layer 1 of Long 11. 2) Organic pores, inorganic pores, and fractures are important reservoir spaces, among which organic pores and fractures are important seepage channels for shale gas. 3) The shale pore structure revealed by electron microscopy shows that the pore structure in target layers can be divided into four types: unimodal type (mainly organic pores), bimodal type (both organic and inorganic pores), monoclinic type I (mainly organic pores), and monoclinic type II (mainly inorganic pores). The pore morphology is complex, and circular and oval shapes predominate. 4) Sedimentary facies are the main factor controlling the enrichment of shale gas, and the development of fractures is the key to obtaining high yields of shale gas. 5) The class I favorable target area is mainly distributed in wells W206, W206H1, R234H, and R233H and areas to its south, and some areas in the east of the study area.

Engineering geological and petrological characterization of paleoweathered rock in the K1/J2 contact zone in the Ordos Basin, China

Various geological processes (mineral composition, structure, tectonics, weathering, etc.) affect the physical–mechanical properties of rock. Petrological and engineering geological characteristics of paleoweathered rock (PWR) from the K1/J2 contact zone are described in detail via field investigation and experimental testing. This PWR exhibits mainly sandy grains and mud structures, layered and massive strata, and calcareous and argillaceous cements; fissures are developed and often filled with argillaceous and detrital materials; nine minerals and seven oxides are present, and quartz is present in each sample. Long-term weathering results in a consistent bulk density and high total porosity due to the transformation of primary minerals into secondary clay minerals, forming PWR that undergoes argillization in water. The axial point load strength (PLS) is the largest among the tested PLSs, followed by the diametral PLS, and the irregular PLS. The uniaxial compressive strength (UCS) varies widely, but the results are reliable. The mineralogical, physical and mechanical properties of the PWR are compared to predict one parameter from another and study their mutual influence. The PLS and UCS of the PWR are negatively correlated with the elastic mineral group (EMG) content, weathering alteration indexes, water content, and total porosity and positively correlated with the quartz content, brittle mineral group (BMG) content, bulk density, real density, and longitudinal wave velocity. The UCS and the PLS, axial (diametral) PLS and irregular PLS are positively correlated. These results provide a theoretical basis for physical and mechanical property prediction of PWR masses and rapid estimation of UCS in engineering.

Study of the Effect of Mineral Components on the Permeability Impairment Rate and Stress Sensitivity Factor of Shale

The mineral components play an indispensable role in shale reservoirs, and the study of their content and character are significant for the permeability impairment rate and stress sensitivity of shale reservoirs. In this study, the shale cores from the FC1 well of the Lower Cambrian Niutitang Formation in northern Guizhou were used to analyze the mineralogical composition of five samples using X-ray diffractometry and for measurement of permeability and porosity of samples by means of the FYKS-2 high-temperature overburden porosimeter with N2, and the samples were also subjected to uniaxial compression tests using the INSTRON 1346 electrohydraulic servo-controlled material testing machine (200T), thereby analyzing the effect of mineral components on the permeability impairment rate and stress sensitivity coefficient of shale. Results indicate that the permeability and porosity are negatively correlated with effective stress and clay mineral content, and positively correlated with detrital mineral content, whereas, the change of mineral composition is not obvious for porosity. Simultaneously, the permeability impairment rate and stress sensitivity factor decrease with growing quartz content and modulus of elasticity, and increase with rising clay mineral content. Additionally, the greater the brittle minerals content of shale, the more likely it is to undergo brittle damage and more crack extension during compression with predominantly elastic deformation, resulting in a lower stress sensitivity factor. Conversely, the higher is the stress sensitivity factor. The research results further deepen the understanding of mineral components on the permeability and mechanical properties of shale reservoirs.

Fine Logging Evaluation of Fractures in Continental Tight Oil Sandstone Reservoirs of Yanchang Formation in the Ordos Basin

Fractures are the main seepage channels in tight reservoirs, and they affect the distribution of high-quality reservoirs and the enrichment of hydrocarbons. Fine logging identification of fractures in the strongly heterogeneous continental tight oil reservoirs of the Upper Triassic Yanchang Formation in the Ordos Basin is a hot and difficult point in the field of petroleum geology. In this paper, taking the Yanchang Formation as an example, a fractal model was constructed to identify fractures in tight oil reservoirs using a large number of cores, conventional and micro-resistivity imaging logging data. The results show that high-angle, vertical and bedding fractures are mainly developed in the Yanchang Formation tight sandstones. There is a negative correlation between sand body thickness and fracture development degree. The fracture sensitivity parameters were used to construct a coupled fractal fracture index. The fractal model incorporates logging information from natural gamma, acoustic wave time difference, rock density, and shallow lateral resistivity. In addition, the constructed fracture fractal index realizes the functions of multi-conventional logging information fusion, which can effectively identify fracture development segments in sandstone. According to the statistics, the fracture identification rate is 83.3%. The study also found that with the increase of sandstone brittleness index, the fracture index has a “S” shape increasing trend. Therefore, the content of brittle mineral components in sandstone is an important factor affecting the development degree of natural fractures, and fractures are more likely to occur in high brittle, thin sand bodies. The highly brittle framework minerals have strong stress-supporting capacity, which can keep fractures open by resisting high overlying loads.

Structural setting of the Narusongduo Pb-Zn ore deposit in the Gangdese belt, central Tibet

The Narusongduo Pb-Zn deposit is located at the northern boundary of the Luobadui-Milashan fault zone (LMF) in central Tibet and is spatially associated with the Linzizong volcanic succession (LVS). Our study indicates that the regional structural setting was formed by two-stage tectonic events. The first stage, spanning from the late Mesozoic to early Paleocene, is characterized by significant N-S crustal shortening associated with the Cordilleran-type orogeny along the Gangdese arc. The region's Paleozoic-Mesozoic metasedimentary rocks were penetratively strained. Locally deformation was largely partitioned along the LMF. During the second stage (ca. 66–55 Ma), the area was affected by extensive multi-stage Linzizong volcanism, including caldera formation, as well as a coaxial N-S propagative deformation with a distinctive lower shortening rate. We recognized two types of mineralization, both were formed during the second stage. The first type of mineralization (orebody III) is governed by fractures within the extensively deformed Paleozoic carbonate rocks at the LMF's footwall. The overlying LVS, however, includes discrete but numerous mineralized sections. The terminal splays of the ore shoots typify the products of hydraulic fracturing. We propose that the propagative compressive deformation drained fluid reservoirs at depth to higher levels via the “Fault valve” effect. Episodic fluid influxes and mineral deposition formed the time-integrated mineralization. The second type of mineralization (orebody I) is hosted in the LVS in a number of breccia pipes and dykes that were controlled by the structural weaknesses generated by the intersection of the radial and ring fractures. Mineralization occurs as veinlets in the matrix and clasts inside the breccias, which are characterized by multi-stage brittle cracking, fluid injection and mineral precipitation. It is interpreted that the multi-stage magmatism (ca. 66–55 Ma) triggered repeated hydrothermal activities and incremental mineralization within the ore-bearing breccia bodies.

Composition Effect on the Pore Structure of Transitional Shale: A Case Study of the Permian Shanxi Formation in the Daning–Jixian Block at the Eastern Margin of the Ordos Basin

Marine–continental transitional (hereinafter referred to as transitional) Permian shales are important targets for shale gas in China because of the considerable volumes of shale gas resources present in them. In this study, transitional shale samples from the Permian Shanxi Formation in the Daning–Jixian block along the eastern margin of the Ordos Basin were collected to investigate the effects of organic and inorganic compositions on the development of their pore structures through organic petrographic analysis, X–ray diffraction, scanning electron microscope (SEM) observation, gas (N2 and CO2) adsorption, high-pressure mercury injection (HPMI), and methane adsorption experiments. The organic petrographic analysis reveals that the Permian Shanxi shale comprises Type-II2-III kerogens, and the average vitrinite reflectance (Ro) is 2.3% at the overmature stage or in the dry gas window. The shale interval at the bottom of the lagoon facies is considered the most favorable interval throughout the entire section because of its high total organic carbon (TOC) content (4.19–43.9%; an average of 16.9%) and high brittle mineral content (38.3–73.2%; an average of 55.8%). N2 and CO2 gas adsorption and HPMI tests reveal the pore size distribution characteristics of the shale. The full pore size distribution by the gas adsorption and HPMI test reveals that micropores (&amp;lt;2 nm) and mesopores (2–50 nm) were dominant in the pore system, and the contributions of the two pore sizes were nearly equivalent, accounting for 21.95–55.05% (an average of 42.3%) and 37.94–64.6% (an average of 49.64%) of the total pore volume, respectively. Additionally, the pore characteristics related to different phases (mainly as silicate, clays, and organic matter) are further clarified by SEM observation and correlation analysis of phase content and pore structure parameters. OM contains numerous SEM-invisible micropores, whereas clay minerals mainly develop mesopores and small macropores (50–100 nm). Furthermore, we calculated the contribution of different shale components to shale porosity. The OM pores account for 0.26–44.1% (an average of 18.7%), and clay mineral pores account for 53.8–93.3% (an average of 76.9%) of the shale porosity. In particular, the OM contributes 73.2% to the surface area and 33.5% to the pore volume. This implies that both OM and clay minerals are important for the storage capacity of adsorbed and free gas.

Geological characteristics, evaluation criteria and discovery significance of Paleogene Yingxiongling shale oil in Qaidam Basin, NW China

Major breakthroughs of shale oil exploration have been made recently in the upper member of Paleogene Lower Ganchaigou Formation of Yingxiongling area, Qaidam Basin. However, the low total organic carbon content of saline-lacustrine source rock, and unclear genetic mechanism, evaluation criteria and resources potential of the shale oil have restricted the exploration and evaluation of Yingxiongling shale oil. Through analysis of large amounts of cores, well drilling, seismic, laboratory test data and integrated study, focusing on the shale and mixed types of shale oil reservoirs characterized by high-frequency interbedded organic-rich laminated shale and limy dolomite, it is concluded that the shale oil in the upper member of Lower Ganchaigou Formation in the Yingxiongling area have six geological characteristics: (1) two-stage hydrocarbon generation of hydrogen-rich source rock and large amount of retained oil; (2) multiple types of reservoir space and good reservoir properties; (3) source-reservoir integration, thick “sweet spot” and high oil-bearing grade; (4) high pressure coefficient between and under salt layers, and sufficient formation energy; (5) high content of light components, high gas-oil ratio, and good quality of the crude oil; (6) high content of brittle minerals and good fracability. The evaluation criterion of shale oil is preliminarily established based on the eight parameters: total organic carbon content, maturity, effective porosity, oil saturation, brittle mineral content, pressure coefficient, lamellation density, and burial depth. Combined with parameters of E32 source rock thickness, area, vertical distribution of oil layers, and free hydrocarbon content, the shale oil resources have been preliminarily estimated as 21×108 t. The structurally stable area is the predominant objective of shale oil exploration and the favorable exploration area for Yingxiongling shale oil is nearly 800 km2.

Evaluation of the Accumulation Conditions and Favorable Areas of Shale Gas in the Upper Palaeozoic Marine-Continental Transitional Facies in the Daning-Jixian Area, Ordos Basin

This study focuses on the organic-rich mud shale in the Upper Palaeozoic transitional facies in the southeastern margin of the Ordos Basin. It systematically analyzes the shale gas accumulation conditions of the organic-rich mud shale in the Lower Permian Shanxi-Taiyuan Formation, including the thickness, distribution, organic matter type and content, thermal maturity, reservoir space, gas-bearing property, and rock brittleness. The results show that the thick dark mud shale contains a high organic matter content, is a suitable kerogen type for gas generation, and exhibits moderate thermal evolution, providing excellent conditions for hydrocarbon accumulation. Residual primary pores formed by shale compaction, secondary pores formed by organic matter hydrocarbon generation, clay mineral transformation and dissolution, and fractures provide suitable reservoir spaces for shale gas. The shale in the study area has a higher gas content than the shale strata in the marine basins of the United States. In addition, the content of brittle minerals such as quartz is higher, and Poisson’s ratio is lower, facilitating the subsequent transformation. The accumulation conditions indicate the high potential of the study area for shale gas exploration and development. The geological analogy method is used to compare the study area with five major shale gas basins in the United States. The results indicate that the shale gas resources of the Shanxi-Taiyuan Formation in the study area are in the range of 2800– 3200 × 10 8 m3. The primary controlling factors affecting shale gas reservoirs in this area are the abundance of organic matter, thermal maturity, shale thickness, and quartz content. Favorable areas are predicted based on these factors.

Experimental investigation of the damage characteristics and breaking process of shale by abrasive waterjet impact

Perforation is critical to create a flow pathway between a shale reservoir and the production casing for hydraulic fracturing. However, the damage characteristics of shales by abrasive waterjet (AWJ) remain unclear. To address this concern, AWJ experiment is conducted for three types of shale with different mineral compositions, including siliceous shale, calcareous shale, and carbonaceous shale. X-ray diffractometry measures the content of mineral components. A rock mechanics test system obtains the main physical and mechanical parameters of shale samples. Scanning electron microscope (SEM) and acoustic emission (AE) are used to analyze the damage characteristics. The results indicate that siliceous shale with more brittle minerals is beneficial for the AWJ to create a larger perforation effectively, while carbonaceous shale with more clay minerals significantly lowers AWJ performance. For the shale with more brittle minerals, abrasive erosion and matrix spallation govern shale failures. As the clay content increases, the primary rock damage is abrasive cutting leading to the transgranular fracture. AE signals induced by AWJ impact could reflect breaking mechanisms and identify the difference in shale lithology. The energy dissipation gradually reduces during the AWJ process. Also, the dissipation has a negative linear correlation with the content of brittle minerals. This study provides fundamental insight into understanding shale damage by AWJ impact to optimize the perforation scheme.

Coupling Relationship between Lithofacies and Brittleness of the Shale Oil Reservoir: A Case Study of the Shahejie Formation in the Raoyang Sag

Analyzing the characteristics of rock brittleness in low-permeability mudstone and shale (MS) formations is imperative for efficient hydraulic fracturing stimulation. Rock brittleness depends on the mineral composition, organic matter abundance, and bedding structure. Based on the MS from Shahejie Formation mineral composition (clay mineral, felsic mineral, and calcareous mineral contents), total organic content, and bedding structure (laminated, laminar, and massive), six types of lithofacies were identified: clay-rich MS, felsic-rich MS, calcareous-rich MS, clay MS, felsic MS, and calcareous MS. The quartz, feldspar, calcite, and dolomite of the Shahejie Formation are brittle minerals. Consequently, lithofacies with high felsic and calcareous mineral contents are more brittle. In addition, laminated and laminar MS are also conducive to hydraulic fracturing. Therefore, laminated, organic-rich, and calcareous-rich MS are the dominant lithofacies for hydraulic fracturing in the Shahejie Formation. The lithofacies and brittleness index were predicted by the response characteristics between mineral compositions and logging curves. The 3521–3552 m section of well B11x is dominated by calcareous-rich MS with developed laminae, representing a favorable section for hydraulic fracturing. Fragile minerals and oil are widely developed in the lower part of the lower 1st member of the Shahejie Formation (Es1L) in the southwestern part of Zhaohuangzhuang-Suning, where hydraulic fracturing can be used to increase shale oil production.

Investigation of Flowback Behaviours in Hydraulically Fractured Shale Gas Well Based on Physical Driven Method

Due to the complex microscope pore structure of shale, large-scale hydraulic fracturing is required to achieve effective development, resulting in a very complicated fracturing fluid flowback characteristics. The flowback volume is time-dependent, whereas other relevant parameters, such as the permeability, porosity, and fracture half-length, are static. Thus, it is very difficult to build an end-to-end model to predict the time-dependent flowback curves using static parameters from a machine learning perspective. In order to simplify the time-dependent flowback curve into simple parameters and serve as the target parameter of big data analysis and flowback influencing factor analysis, this paper abstracted the flowback curve into two characteristic parameters, the daily flowback volume coefficient and the flowback decreasing coefficient, based on the analytical solution of the seepage equation of multistage fractured horizontal Wells. Taking the dynamic flowback data of 214 shale gas horizontal wells in Weiyuan shale gas block as a study case, the characteristic parameters of the flowback curves were obtained by exponential curve fittings. The analysis results showed that there is a positive correlation between the characteristic parameters which present the characteristics of right-skewed distribution. The calculation formula of the characteristic flowback coefficient representing the flowback potential was established. The correlations between characteristic flowback coefficient and geological and engineering parameters of 214 horizontal wells were studied by spearman correlation coefficient analysis method. The results showed that the characteristic flowback coefficient has a negative correlation with the thickness × drilling length of the high-quality reservoir, the fracturing stage interval, the number of fracturing stages, and the brittle minerals content. Through the method established in this paper, the shale gas flowback curve containing complex flow mechanism can be abstracted into simple characteristic parameters and characteristic coefficients, and the relationship between static data and dynamic data is established, which can help to establish a machine learning method for predicting the flowback curve of shale gas horizontal wells.

Lithofacies types, reservoir characteristics, and hydrocarbon potential of the lacustrine organic-rich fine-grained rocks affected by tephra of the permian Lucaogou formation, Santanghu basin, western China

Volcanisms were widespread during the Permian periods in the Santanghu Basin. However, information on the classification of the lithofacies of the Lucaogou Formation (Lucaogou Fm) is still lacking, and the hydrocarbon potential of the organic-rich fine-grained rocks (FGRs) remains uncertain. Therefore, this study determines the lithofacies classification standard of the Lucaogou Fm FGRs, clarifies the advantageous lithofacies types, and evaluates the unconventional resource potential based on organic geochemical analysis, macroscopic core observation, core routine test, rock mineral identification, and pore structure characterization. The Lucaogou Fm FGRs are mainly composed of felsic minerals and dolomite, which can be divided into four rock types with high organic matter (OM) content and laminated structure. Based on TOC, rock type, and sedimentary structure, ten types of lithofacies were determined: organic-rich massive tuff (ORMT), organic-medium massive tuff (OMMT), organic-medium massive dolomite (OMMD), organic-poor massive dolomite (OPMD), organic-rich laminated tuffaceous dolomite (ORLTD), organic-medium laminated tuffaceous dolomite (OMLTD), organic-poor laminated tuffaceous dolomite (OPLTD), organic-rich laminated dolomitic tuff (ORLDT), organic-medium laminated dolomitic tuff (OMLDT), organic-poor laminated dolomitic tuff (OPLDT). There is a large amount of algal OM in the Lucaogou Fm FGRs because of the deposition of tephra, but they seriously hinder the development of pore space and the flow of pore fluid due to the relatively low maturity, resulting in poor pore structure and fluid mobility. Among them, ORMT, OPMD, OMMT, and OMMD have been transformed by diagenesis, with various types and scales of pore space, and obviously good physical properties, oiliness, pore structure, as well as fluid mobility. Followed by OPLTD, ORLTD, and OMLTD, while OPLDT, OPLDT, and OMLDT are the worst. The advantageous lithofacies of the Lucaogou Fm FGRs are influenced by both rock types and OM abundance, and are also related to sedimentary structures. In addition, the Lucaogou Fm FGRs have a large thickness, high-quality OM, high content of brittle minerals, low content of clay minerals, developed micro-nanopores network, and certain producible oil, indicating that they have significant hydrocarbon potential.

Pore evolution in siliceous shales and its influence on shale gas-bearing capacity in eastern Sichuan-western Hubei, China

The Upper Permian siliceous shale reservoir, which was less studied before, is considered to be a successor target of marine Wufeng-Longmaxi shale gas in Sichuan Basin. To deeply explore pore characteristics, evolution process, formation mechanism and their influences on shale gas capacity, we performed a comprehensive multiscale characterization on siliceous shales with different maturities from Dalong and Wujiaping Formations using low-pressure N2 adsorption (N2GA), mercury injection pressure (MIP), field emission scanning electron microscopy (FE-SEM), and methane sorption capacity. Results indicate that shale pore development, especially OM pore development, and physical property are strictly controlled by thermal maturation levels. OM pores are seldom in low-mature shales but are well-developed in high-to over-mature shales. Pore structures in shales with different maturities are determined by different factors. The high TOC content is conducive to developing OM micropores for high-to over-mature shales. High content of brittle minerals is conducive to developing interparticle (interP) pores and dissolved mesopores at high-mature stage. In terms of the data and published articles, we established a general pore evolution model in siliceous shales to illustrate shale pore development process and formation mechanism. Similar to OM pore development, methane sorption capacity is controlled firstly by thermal maturation and secondly by TOC content. It's pointed out that over-mature shales have smaller-sized OM pores compared with high-mature shales, and therefore they have higher specific surface areas and methane sorption capacities normalized to TOC. This indicates that siliceous shales with extremely high maturity still have good shale gas potential, which further expand shale gas exploration in over-mature shale gas reservoir, as well as provide exploration suggestion for the siliceous shale gas reservoirs in south China.

Brittle mineral prediction based on rock-physics modelling for tight oil reservoir rocks

AbstractThe reservoir rocks from Chang-7 member of Yanchang Formation of Ordos Basin are characterised with heterogeneous fabric structures at the pore scale, and low porosity/permeability is exhibited at the macro scale. Precise prediction of reservoir brittleness is of great significance to oil production. Ultrasonic experiments are performed on tight sandstones collected from the target formation. A rock-physics model (RPM) is presented based on the Voigt–Reuss–Hill average (VRH), self-consistent approximation (SCA) and differential effective medium (DEM) theory. The brittleness characteristics relying on mineral composition, porosity and microcrack properties are explored by using the RPM. The Young's modulus increases and Poisson ratio decreases with increasing quartz content. Based on experimental, log and seismic data, brittle mineral analysis of rock physical model is performed at multiple scales. The model accuracy is verified by experimental data and well log data. The brittleness distribution is predicted on the basis of log and seismic data, which can be instructive for the reservoir rock fracturing in actual engineering operations.

The Control of Diagenesis and Mineral Assemblages on Brittleness of Mudstones

The variation in mineral composition will affect the rock brittleness, thus the change of mineral assemblages during diagenesis has a potential control on the brittleness of mudstones. In this study, thin section, X-ray diffraction (XRD), and Scanning Electron Microscope (SEM) analyses were used to investigate compositional and microscopic features of mudstones. With the enhancement of diagenesis, three mineral assemblages were divided due to the diagenetic evolution of minerals. Quartz, feldspar, dolomite, chlorite, and illite were regarded as brittle minerals and (quartz + feldspar + dolomite + illite + chlorite)/(detrital mineral + carbonate + clay mineral) was defined as the brittleness evaluation index The mudstone brittleness changed slightly during early diagenesis but increased gradually with enhancement of diagenesis in the late diagenesis stage. Quartz and feldspar were scattered above the clay matrix and the contact of grains was limited, therefore, the contribution of detrital minerals to the brittleness was affected by the properties of clay minerals. The diagenetic transformation of clay minerals resulted in the reduction of ductile components (smectite/I-Sm and kaolinite) and increase of brittle components (illite and chlorite), leading to the enhancement of integral rigidity of the mudstones. Meanwhile, the improved crystallization of carbonate in late diagenesis stage enlarged the carbonate grains which resulted in rigid contact between grains. These results highlighted the influence of diagenesis on mudstone brittleness. Therefore, for evaluation of mudstone brittleness, attention should be paid to the diagenesis process besides mineral composition.

Integrated Assessment of Marine-Continental Transitional Facies Shale Gas of the Carboniferous Benxi Formation in the Eastern Ordos Basin

In the Benxi Formation of the Carboniferous system of the Upper Paleozoic in the Ordos Basin, there are many sets of coal measures dark organic-rich shale, being marine continental transitional facies, with significant unconventional natural gas potential. Previous studies are only limited to the evaluation of tight sandstone reservoir in this set of strata, with no sufficient study on gas bearing and geological characteristics of organic-rich shale, restricting the exploration and evaluation of shale gas resources. In this study, analysis has been conducted on the organic carbon content, the major elements, the trace elements, and the mineral composition of core samples from the Benxi Formation in key drilling sections. In addition, qualitative and quantitative pore observation and characterization of core samples have been conducted. The sedimentary environments and reservoir characteristics of the shale of the Benxi Formation have been analyzed. Combined with the gas content analyzing the results of the field coring samples, the shale gas resource potentials of the Benxi Formation have been studied, and the geological characteristics of the Benxi Formation shale gas in the eastern Ordos Basin have been made clear, to provide a theoretical basis for shale gas resource evaluation of the Benxi Formation in the Ordos Basin. The results show that (1) in the Hutian Member, Pangou Member, and Jinci Member of the Benxi Formation, organic-rich shale is well developed, with the characteristics of seawater input as a whole. There is a slight difference in sedimentary redox index, which shows that the reducibility increases gradually from bottom to top. (2) There is an evident difference in the mineral characteristics of shale in these three members. The Hutian Member is rich in clay minerals, while the Jinci Member is high in quartz minerals. (3) The pores are mainly inorganic mineral intergranular pores, clay interlayer fractures, and micro fractures, and organic matter pores are developed on the surface of local organic matter. (4) The mud shale in the Jinci Member has a large cumulative thickness, has relatively high gas-bearing property, and is rich in brittle minerals. The Jinci Member is a favorable section for shale gas exploration of the Benxi Formation.