Shale Gas Resource Potential Research Articles

Hydrocarbon generation and expulsion characteristics of the Lower Cambrian Qiongzhusi shale in the Sichuan Basin, Central China: Implications for conventional and unconventional natural gas resource potential

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 10 6 t/km 2 and 18 × 10 6 t/km 2 , respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 10 12 m 3 and 19.03 × 10 12 m 3 . The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 10 12 m 3 , showing significant prospects for natural gas exploration. • Geochemistry characteristics of the Qiongzhusi Formation were systemically evaluated. • Hydrocarbon generation and expulsion characteristics of the Qiongzhusi Formation were first analyzed. • Conventional and unconventional natural gas resource potentials of ancient Lower-Cambrian petroleum system were calculated.

The Permian Tunas Formation (Claromecó Basin, Argentina): Potential naturally fractured reservoir and/or coal bed methane (CBM) play?

The analysis of structural discontinuities in the Tunas Formation helps characterize this unit as a potential naturally fractured reservoir. The principal discontinuities are 1) fractures parallel to the bedding planes, 2) fractures coplanar to the axial planar cleavage, 3) dilatant fractures filled by quartz, and 4) subvertical shear fractures. Over a thousand measurements on microtectonic structures help infer a stress field whose maximum principal stress (σ1) has a SW-NE orientation. Based on this structural analysis, optimal orientations for exploration and/or production wells in the Claromecó Basin should be a 130° azimuth. Fracture spacing range between 30 and 100 cm in outcrops of the Tunas sandstones along the Ventana foldbelt (VFB). A similar fractured network is postulated for the subsurface of the basin.Organic-rich levels, ranging from coals to carbonaceous shales, occur in the Tunas Formation in the subsurface of the Claromecó Basin and are a potential shale gas resource play. These beds tend to cap successions of interbedded shales and sandstones. The coals range from semi anthracitic to low volatile bituminous. Vitrinite and fusinite prevail as organic matter types, ranging between 1.3 and 2.4 vitrinite reflectance (Ro). The occurrence within condensate-wet gas to dry gas windows reflect subsurface processes such as strong diagenesis and anchimetamorphism. The coal-rich levels in the Tunas Formation can be correlated with other Lower Permian organic-rich units in the Paraná Basin in Uruguay (Tres Islas Formation) and Brazil (Rio Bonito Formation). All are analogous to the lower Upper Permian Vryheid coals of the eastern Karoo Basin in South Africa with shale gas and coal bed methane (CBM) prospectivity.

The Enrichment Conditions and Resource Potential of Marine-Continental Transitional Coal-Measure Shale Gas: A Case Study of the Permo-Carboniferous Systerm in the Huanghebei Coalfield of North China

Coal-measure shale gas is considered to be an important unconventional oil and gas resource in coal measures. At the present time, coal-measure shale gas has not been well studied. However, in recent years, such potential resources have received increasing attention. In this research investigation, the coal measures of the Permo-Carboniferous Period in North China’s Huanghebei Coalfield were taken as the research object in order to evaluate the enrichment conditions and resource potential of the coal-measure shale gas. The results were as follows: 1) A variety of sedimentary environments were developed during the Late Paleozoic Era in the Huanghebei Coalfield region. Lagoon sediment had mainly developed in the Taiyuan Formation, which was conducive to the high-intensity development of shale. In addition, interdistributary bay-floodplain sediment had developed in the Shanxi Formation, which was also favorable to the development of shale; 2) The average value of the total organic carbon (TOC) in the shale of the Taiyuan and Shanxi Formations in the study area was found to be more than 2%. The main type of organic matter was Type II kerogen, followed by Type III kerogen. Furthermore, the thermal evolution degree of the organic matter was considered to be in the mature stage, which indicated a good hydrocarbon generation potential; 3) The gas bearing intervals of the shale in the Taiyuan and Shanxi Formations in the study area were mainly variegated shale, mudstone, carbonaceous shale, and silty mudstone (shale), which belong to the categories of ultra-low permeability and low porosity reservoirs; 4) The average gas content of mud shale in the Taiyuan and Shanxi Formations ranges between 0.645 and 3.34 m3/t. The shale tends to have large burial depths and well-developed caprock, which is conducive to the preservation of shale gas; 5) This study’s comprehensive analysis results showed that the mud shale in the Taiyuan and Shanxi Formations have good hydrocarbon generation potential. A favorable area was delineated in the middle of the Huanghebei Coalfield, and a NE-trending belt distribution was evident along the Pandian-Qihe-Biaobaisi. In summary, the three delineated perspective areas were determined to be the Dulangkou-Zhaoguan prospect area; Yuchengnan prospect area; and Sangzidian prospect area, respectively.

Depositional environment and thermal maturity of the coal-bearing Longtan Shale in southwest Guizhou, China: Implications for shale gas resource potential

Significant knowledge has been assembled on the marine Longmaxi Shale in the Sichuan Basin over the past ten years. However, the distribution of shale gas resources on the periphery of the Sichuan Basin and in other source rock formations are still not sufficiently understood. To improve our understanding on the depositional environment and thermal maturity, and their relevance to the source rock quality and shale gas potential of the thick, coal-bearing Longtan Shale, 36 organic-rich shale samples were selected from a single borehole located in the southwestern Guizhou Province for geochemical and petrographic analysis.Total organic carbon (TOC) contents are high with 7.7 wt% on average, reaching partly up to 28.21 wt%, while carbonate contents are low. Vitrinite reflectance (VRr) values and Rock-Eval Tmax temperatures range from 1.48 to 1.84% and 482 to 583 °C, respectively, indicating a high thermal maturity which is in accordance with aromatic molecular parameters. The remaining, present day hydrocarbon generation potential (Rock-Eval S2) is rather low due to the high maturity. Microscopic investigations further show that the organic matter in the rocks is mainly composed of higher land plant particles, present as large and poorly rounded vitrinite and inertinite particles indicating a rather short transport distance.TOC vs. total sulfur (TS) relationships as well as specific hydrocarbon ratios (e.g. pristane/phytane) and framboidal pyrite size distributions indicate a variable either marine or freshwater environment for the shales in the coal-bearing sequence and suggest that original kerogen was either type III or type II-III. Bottom water during deposition was probably oxygen depleted but not anoxic. High sedimentation rates can be assumed for the now 700 m thick, compacted sequence, favorable for the preservation of organic matter.Overall, the present results are in accordance with previous studies of the Longtan Shale which initially had a high hydrocarbon (mainly gas) generation potential; furthermore the thickness of the formation is much larger in the here studied southwestern part of the Guizhou Province than in the previously studied northern parts.

Controls on gas storage characteristics of Upper Paleozoic shales from the southeastern Ordos Basin

Abstract Potential shale gas resources in China are not only of marine but also of marine-terrigenous transitional and continental origins. To analyze the controls on gas storage capacity of shales from the Carboniferous Benxi and Permian Shanxi formations, high-pressure/temperature methane sorption isotherms (up to 25 MPa and 120 °C) and porosity have been measured on 12 samples from the Yishan slope. Total organic carbon (TOC) content of Shanxi and Benxi shales are low to moderate from 0.1% to 80%) is stored on clay minerals (illite/smectite mixed layer and kaolinite) controlling both sorption capacity and porosity. TOC content, due to its low values, is of minor importance. Benxi and Shanxi shales possess comparatively low gas storage capacities compared to producing marine shale gas systems. Combined with the large amount of clay minerals that make hydraulic fracturing more difficult they are regarded unfavourable for shale gas exploitation. Although a substantial amount of gas can be stored sorbed in excess of the free gas in gas shales, methane sorption has a negligible effect on gas production at pressures above 10 MPa. This has major implications for deep reservoirs where pore pressures in the matrix may not be reduced sufficiently before production ceases.

SHALE GAS SWEET SPOT POTENTIAL OF TUNGKAL GRABEN, JAMBI SUB-BASIN SOUTH SUMATERA BASIN

The Tungkal Graben is located in Jambi Sub-basin, the northern part of South Sumatera Basin. This basin is known as one of the largest hydrocarbons producing basin in Indonesia. There are several proven source rocks in the South Sumatera Basin. The paralic shales and coal horizon of Talangakar Formation (TAF) are known as primary source rock in this basin and considered as a reservoir of shale gas-bearing in Tungkal Graben Area as well. This study used surface geological data that was collected from the southern foot of Tiga Puluh Mountain as the outcrop analogy and subsurface data (existing well and seismic data) in Tungkal Graben Area. This study applied integrated methods including environmental deposition analysis, organic geochemistry analysis, petrophysical analysis, seismic interpretation, sweet spot delineation, and volumetric of gas in place (GIP) calculation. TAF observed both on the outcrop and well is transition deposit that consists of the dominance of shale and siltstone with interbedded of coal, sandstone, and limestone. Shale and siltstone of TAF have characteristic which is appropriate as a shale gas bearing, with sufficient organic content richness, suitable kerogen type, its maturity entering the early gas generation and proper brittleness index (BI). The sweet spot area is an area that has met the criteria for potential shale gas and determined by pay zone criteria. Depend on the criteria, Net to gross for shale gas is 0.158, early gas generation estimated at a depth of 10250 feet, and sweet spot area reaches 8.9 x 108 ft2. Thus, the total potential of shale gas resources from the calculation using the Ambrose method is 2.12 TCF.

Organic geochemical and petrophysical characteristics of transitional coal-measure shale gas reservoirs and their relationships with sedimentary environments: A case study from the Carboniferous-Permian Qinshui Basin, China

The Carboniferous-Permian Qinshui Basin has shale gas resource potential. In this study, eighteen shale samples from two representative wells were analyzed to investigate the coal-measure shale reservoir characteristics and their relationships with the transitional sedimentary environments. The results show that controlled by sedimentary environments, the tidal flat and barrier-lagoon (TFBL) system is prone to developing more organic matter (OM) than the pro-delta and delta front (PDDF) and delta plain and fluvial (DPF) systems. Shale porosity is positively correlated with clay mineral content, but shows no obvious relationship with quartz content. However, biogenic quartz content exhibits a negative correlation with shale porosity, but has a positive correlation with shale brittleness in the PDDF system, while no obvious correlation between detrital quartz and reservoir quality is found in the TFBL system. In terms of its better preservation of pyrite, which improves shale reservoir brittleness, there is more enhancement of the shale reservoir quality within the TFBL system than the PDDF system. The coal-measure shale samples exhibit a positive logarithmic correlation between reservoir porosity and permeability due to the pore size distribution. In terms of micropores (pore size < 2 nm), interlaminar OM micropores and clay mineral micropores are mainly controlled by hydrodynamic intensity, while columnar OM micropores are dominated by TOC content. Compared with the PDDF and DPF systems, the TFBL system is prone to forming laminar structures of shale in response to the sedimentary environment changes, which favor pore network development. The results of this study aim to provide a basis for shale gas exploration in coal-measure intervals in the Qinshui Basin and other similar transitional basins.

Exploration and development potential of the low-maturity continental shale gas in the Fuxin Basin

In order to promote the exploration and development of continental shale gas reservoirs in China further, we systematically summarized the geological features of typical continental shale, such as the Ordos Basin. Then, the shale gas reservoir characteristics, geochemical characteristics and fracturing performance of the Lower Cretaceous Shahai Fm in the Fuxin Basin were analyzed by using the data of TOC contents, rock specific surface, pore size distribution and X-ray diffraction analysis of the whole rock. Based on this, it was compared with the marine/continental shale gas reservoirs from the aspect of geological feature. Finally, the shale gas reservoir and resource potential of the Shahai Fm were evaluated. And the following research results were obtained. First, the formation age of China's continental shale is later, its TOC contents vary in a large range, and its organic matters are mainly of a mixed-humic type. And it is characterized by low thermal evolution degree, low quartz content, high feldspar content, high carbonate content, and comparability of total brittle mineral content to marine shale. Second, shale in the Shahai Fm has shallow burial depth and its mineral composition is dominated by quartz, feldspar and carbonate minerals. Its pores are mainly mesopores with an average porosity of 3.47%. There are diverse reservoir spaces, which is favorable for the accumulation of shale gas. Third, the TOC content of the Shahai Fm shale is mainly above 2%, with a moderate thermal evolution degree of organic matter and high gas content. Fourth, the total brittle mineral content of Shahai Fm shale is up to 60%, indicating a good fracturing performance. Fifth, shale reservoirs in the Shahai Fm can be classified into three categories. Type I is target reservoirs of exploration and development, and Type II is favorable reservoirs. It is estimated that the amount of shale gas resources are in the range of 232.2–286.2 billion m3. It is concluded that the Shahai Fm shale in the Fuxin Basin has both resource potential in geology and fracturing performance in engineering, and its exploration and development prospect is broad. What's more, the potential of commercial shale gas development is great in the sweet-point areas.

Potensi Gas Serpih Formasi Pulobalang, Cekungan Kutai, Kalimantan Timur

Kutai Basin has proven to be a productive basin and has great potential, this fact indicating the existing petroleum system has been running well. Therefore, more specific investigations need to be carried out, especially for development of non-conventional hydrocarbon reserves, and find out in detail the characteristics of rocks that have potential to be carriers of potential shale gas in the Kutai Basin. The used data in this study included 5 (five) drilling wells, Ramin-1, Rasamala-1, Buat-1, Busang-1, and Murung-1 which contained wireline log data, mud logs, biostratigraphic analysis, geochemical analysis, and 81 line 2-D seismik trajectories. Further interpretation using geochemical data and modelling with Passey Method. In geomechanical data analysis, modeling used wireline logs, produce Young modulus values, Poisson ratios, and rock brittleness. Petrophysical analysis was used to be a parameter of rock quality. These data are depicted vertically and horizontally with seismic data benchmark, resulting in facies distribution and rock quality parameters as shale gas reservoirs. The research showed that Pulobalang Formation in the study area, deposited in the deltaic to slope environment, with type III kerogen, TOC content level poor until excellent with 0.12 - 7% value and brittleness value 0.05-0.971. The calculation was conducted based standard criteria as shale gas reservoir. Total potential of shale gas resources in the Pulobalang Formation reaches 2.78 TCF.

Sedimentary facies distribution and the characteristics of transitional shale in the upper Palaeozoic in northeast Ordos basin, China

The Taiyuan formation that was formed in the late Permian period of the upper Palaeozoic in the Linxing area, north-eastern of Ordos basin, China, shows the marine and continental interdepositional systems, as well as the resource potential of shale gas. Through a field outcrop, core observation, and well logging data, the Taiyuan formation can be divided into Tai1 (p1t1) and Tai2 formations (p1t2). The main depositional environments of the region in Taiyuan formation included tidal flats, swamp, and lagoon which is also a good depositional environment for high-quality shale development. During the Taiyuan formation period, the sedimentary sea level in the study area rose and fell frequently, and the barrier coastal sedimentary system is mainly developed. In addition, the shale has superior development characteristics: The Taiyuan formation shale has a considerable amount of material, with an accumulated thickness of greater than 30 m; the average organic carbon content in the Taiyuan group is 3.34%, and the content in the Tai2 formation (p1t2) is slightly higher than in the Tai1 formation (p1t1); a high thermal evolution content is developed with an average vitrinite reflectance (Ro) of 1.33%; the Kerogen type is the III model, in which gases are mainly developed; the brittle mineral content in the rock mineral components is high, and the brittleness index is generally greater than 50%, which indicates a high rate of compressibility. Therefore, the Taiyuan formation indicates a marine and continental interdeposition and has a high exploration and development potential for shale gas.

The Sinian-Cambrian formation shale gas exploration and practice in southern margin of Huangling paleo-uplift

The Sinian Doushantuo and the Cambrian Niutitang formations in southern China have a good shale gas resource potential. Although >20 wells have already been drilled in these formations, the shale gas production has been much lower than expected, due to the high thermal maturity of the rocks and the severely disturbed geological structure of the corresponding area. An industrial gas flow was discovered only in the Weiyuan region. To achieve the shale gas breakthrough of paleo-shale strata, it is necessary to find a shale reservoir with low thermal maturity and weak geological deformation. On the basis of the study on the Weiyuan, Huangling and other paleo-uplifts, a shale gas accumulation mechanism named “shale gas accumulating around the edges of paleo-uplifts” was proposed. It has been suggested that the shale gas is usually contained within the slope belt of a paleo-uplift margin characterized by a shallow burial depth, stable structure activity, and a low level of thermal maturity. Taking into account this accumulation mechanism, a large number of wells have been drilled on the southern edge of the Huangling paleo-uplift (western Hubei province). Organic-enriched shales with high shale gas content and low thermal maturity, have been found within the Sinian Doushantuo and the Cambrian Niutitang formations. To tackle the problems deriving from the low exploration level, complex geological structure, low temperature, and low pressure in the region, we proposed and applied innovative fracturing process, new complex fracturing techniques and new recovering technology systems. High and stable shale outputs were obtained from the Niutitang Formation (well Yangye-1HF, HF: Horizontal Well Fracturing) and from the Doushantuo Formation (well Yangye-2HF): 7.83 × 104 and 5.53 × 104 m3/day, respectively. These outputs were achieved following horizontal well section fracturing, which resulted in a significant breakthrough for the production capacity of the low-pressure shale gas reservoir in the complex tectonic region outside of the Sichuan Basin.

Hydrocarbon generation and expulsion characteristics of the source rocks in the third member of the Upper Triassic Xujiahe Formation and its effect on conventional and unconventional hydrocarbon resource potential in the Sichuan Basin

Abstract The third member of the Upper Triassic Xujiahe Formation (T3x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T3x3 as a source rock, ignoring its role as a reservoir. As a result, the evaluation of hydrocarbon resource potential was not accurate. This study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the T3x3 source rocks, and calculated the resource potential of conventional gas, tight gas and shale gas systematically with combining the lower boundary of buoyancy-dominated accumulation (LBBA). The results indicated that the thickness of the source rocks dominated by mudstone was distributed widely, with an average value of more than 45 m. The sedimentary environment was salty lacustrine deposits. They have a high content of total organic carbon (TOC) with an average value of 4.80 wt%, the kerogen is mainly type III with minor type II, and the thermal evolution has entered the high to over mature stage. The hydrocarbon generation threshold was determined to be 0.5%Ro, while the hydrocarbon expulsion threshold and the LBBA were determined to be 0.83%Ro and 1.12%Ro, respectively. The efficiency of hydrocarbon expulsion was relatively high, with an average of about 56%. Also, the maximum hydrocarbon generation and expulsion intensity reached to 110 × 108 m3/km2 and 53 × 108 m3/km2. The amounts of hydrocarbon generation, expulsion and residual associated with the T3x3 source rocks were 125.68 × 1012m3, 70.38 × 1012m3, and 55.30 × 1012m3, respectively. Under the criterion condition of the LBBA, the conventional gas resource was 7.21 × 1010m3, the tight gas resource was 294.34 × 1010m3, and the shale gas resource was 2488.50 × 1010m3. It indicated good prospects for exploration.

Enrichment laws and scale effective development of shale gas in the southern Sichuan Basin

Based on the newest understandings of geological assessment and new progresses in engineering technologies in the development of shale gas rich in the southern Sichuan Basin, this paper analyzed the shale gas enrichment laws and the key factors of its commercial production, discussed the scale and efficient development modes, and clarified the further developing orientation. The following findings were concluded. (1) The Lower Silurian Longmaxi shale is the sweetest spot in this study area with a low density and a high uranium/thorium (U/Th) ratio, TOC content, quartz content, and free gas content. Besides, its distribution laws are mainly controlled by the sedimentary facies of deep water shelf. (2) The overpressured zones away from the ancient (present) erosion zones and large faults, mainly controlled by multi-stage tectonic evolution, belong to the most favorable sweet spots not only because there are well-developed organic matters and pores but the produced gas there is mainly of secondary cracking retention oil. (3) Layout, drilling, completion (fracturing) and management of wells will be essential to achieve high productions in the shale gas production. (4) The existing main technologies have helped achieve efficient development of quality shale gas resources underground less than 3500 m in such national shale gas demonstration zones as Changning–Weiyuan, Zhaotong, etc. Also, there shows a good potential of shale gas resources in those shallower strata and the strata with the burial depth of 3500–4000 m. In conclusion, with the help of continuous progress in technologies, an annual shale gas production rate of 40 billion cubic meters will be possibly achieved in this study area.

Elemental Geochemical Evidence for Depositional Conditions and Organic Matter Enrichment of Black Rock Series Strata in an Inter-Platform Basin: The Lower Carboniferous Datang Formation, Southern Guizhou, Southwest China

The Datang Formation black rock series deposited in an inter-platform basin are considered to be one of the main source rocks in Southwest China. However, their depositional conditions and organic matter enrichment in such a setting are not well understood. In this study, geochemical characteristics of total organic carbon (TOC), major, trace and rare earth elements (REEs) of thirty black rock series samples from a newly-cut roadside outcrop (Zhenning section) in Southern Guizhou, Southwest China are systematically investigated to examine provenance, paleoredox conditions, paleoclimate, paleoproductivity and sedimentary rate, and further to explore their influence on organic matter enrichment. Results show that TOC contents of the investigated samples range from 0.90% to 2.83%, with an average of 1.45%, with TOC variations being in accord with the stratigraphic cyclicity. These data also indicate that the target black rock series were deposited in a combination of continental island arc and active continental margin tectonic setting that exhibited moderate weathering, oxic/dysoxic oxygen levels, hot and arid to semiarid climate, and a higher sedimentary rate. Multiple paleoredox indicators (e.g., Ni/Co, V/Cr, U/Th and V/(V + Ni) ratios), together with slightly negative Ce anomalies and EFU-EFMo covariation, totally suggest an oxic/dysoxic water environment, which is usually considered unfavorable for organic matter preservation. Average (La/Yb)N ratios (1.41) reflect a higher sedimentary rate, resulting in shortening the exposure time of organic matter in the degradation region of aerobic bacteria under oxic/dysoxic conditions. Of the three factors that could affect organic matter enrichment, including paleoproductivity, paleoredox conditions and sedimentary rate, the relatively high paleoproductivity indicated by the relatively high TOC contents appears to be the dominant factor. In contrast, the other two factors, i.e., paleoredox conditions and the rate of sedimentation play relatively less significant roles. Based on these factors, an enrichment model of organic matter for the black rock series in Southern Guizhou Depression is established. These findings also contribute to constraining the sedimentary environment in such a setting and further deepen our understanding of the potential shale gas resources of the Southern Guizhou Province.

Organic geochemical characteristics, mineralogy, petrophysical properties, and shale gas prospects of the Wufeng–Longmaxi shales in Sanquan Town of the Nanchuan District, Chongqing

Thick marine shales occur in the Wufeng Formation and Longmaxi Formation of Sanquan Town of the Nanchuan District, Chongqing Municipality, which is located on the southeast margin of the Sichuan Basin. However, few details of the characteristics of the Wufeng–Longmaxi shales in this area have been reported. In this study, a well approximately 100 m (∼328 ft) deep was drilled. A high-quality shale (total organic carbon [TOC] >2.0 wt. %, clay <40%) interval that was approximately 24 m (∼79 ft) thick with an average TOC value of 3.0 wt. % mainly occurs in the Ordovician Wufeng Formation (Katian and Hirnantian) and base of the Silurian Longmaxi Formation (Rhuddanian). Shales with higher TOC values commonly have a higher porosity and specific surface area. Tectonic movements may also have been very important factors that influenced the petrophysical properties of the shales. For example, a detachment layer that resulted from complex tectonic movements is extensive in the Wufeng Formation. The cracks and microcracks in the detachment layer can result in good pore connectivity. Consequently, the detachment layer can be an effective migration pathway. The Longmaxi–Wufeng shales of Sanquan Town are also compared with those of the famous Jiaoye 1 well in the Jiaoshiba shale gas field in the eastern Sichuan Basin. Although the shales in Sanquan Town have considerable shale gas generation potential, the shale gas resource potential in Sanquan Town is probably poor because the escape of shale gas may be accelerated by the detachment layer in destroyed anticlines and synclines.

Optimization of shale gas reservoir evaluation and assessment of shale gas resources in the Oriente Basin in Ecuador

The petroleum geological features of hydrocarbon source rocks in the Oriente Basin in Ecuador are studied in detail to determine the potential of shale gas resources in the basin. The favorable shale gas layer in the vertical direction is optimized by combining logging identification and comprehensive geological analysis. The thickness in this layer is obtained by logging interpretation in the basin. The favorable shale gas accumulation area is selected by referring to thickness and depth data. Furthermore, the shale gas resource amount of the layer in the favorable area is calculated using the analogy method. Results show that among the five potential hydrocarbon source rocks, the lower Napo Formation is the most likely shale gas layer. The west and northwest zones, which are in the deep-sea slope and shelf sedimentary environments, respectively, are the favorable areas for shale gas accumulation. The favorable sedimentary environment formed thick black shale that is rich in organic matter. The black shale generated hydrocarbon, which migrated laterally to the eastern shallow water shelf to form numerous oil fields. The result of the shale gas resource in the two favorable areas, as calculated by the analogy method, is 55,500 × 108 m3. This finding shows the high exploration and development potential of shale gas in the basin.

Gas Occurrence and Accumulation Characteristics of Cambrian–Ordovician Shales in the Tarim Basin, Northwest China

AbstractThe Tarim Basin is located in northwestern China and is the biggest basin in China with huge oil and gas resources. Especially the Lower to Middle Cambrian and Middle to Upper Ordovician possess the major marine source rocks in the Tarim Basin and have large shale gas resource potential. The Cambrian–Ordovician shales were mainly deposited in basin–slope facies with thicknesses between 30–180 m. For shales buried shallower than 4500 m, there is high organic matter abundance with TOC (total organic carbon) mainly between 1.0% and 6.0%, favorable organic matter of Type I and Type II, and high thermal maturity with RoE as 1.3%–2.75%. The mineral composition of these Cambrian–Ordovician shale samples is mainly quartz and carbonate minerals while the clay minerals content is mostly lower than 30%, because these samples include siliceous and calcareous shale and marlstone. The Cambrian and Ordovician shales are compacted with mean porosity of 4% and 3%, permeability of 0.0003×10–3–0.09×10–3 μm2 and 0.0002×10–3–0.11×10–3 μm2, and density of 2.30 g/m3 and 2.55 g/m3, respectively. The pores in the shale samples show good connectivity and are mainly mesopore in size. Different genetic types of pores can be observed such as intercrystal, intergranular, dissolved, organic matter and shrinkage joint. The reservoir bed properties are controlled by mineral composition and diagenesis. The maximum adsorption amount to methane of these shales is 1.15–7.36 cm3/g, with main affecting factors being organic matter abundance, porosity and thermal maturity. The accumulation characteristics of natural gas within these shales are jointly controlled by sedimentation, diagenesis, hydrocarbon generation conditions, reservoir bed properties and the occurrence process of natural gas. The natural gas underwent short‐distance migration and accumulation, in‐place accumulation in the early stage, and adjustment and modification in the later stage. Finally, the Yulin (well Y1) and Tazhong (well T1) areas are identified as the targets for shale gas exploration in the Tarim Basin.

Organic matter, mineral composition, pore size, and gas sorption capacity of lacustrine mudstones: Implications for the shale oil and gas exploration in the Dongying depression, eastern China

Because clay minerals and pore-size distribution are important for oil and gas accumulation in lacustrine mudstone reservoirs, this study aimed to characterize the pore-size distribution in lacustrine mudstone, reveal the importance of clay minerals in gas sorption capacity (GSC), provide insights into the primary GSC controls for lacustrine mudstones, and discuss the shale oil and gas resource potential and possible risks in their future production. A total of 256 core samples from the lower Paleogene sequence of the Dongying depression in the Bohai Bay Basin in China were analyzed to determine organic richness and hydrocarbon generation potential. A series of analyses was conducted on a suite of 28 mudstone samples from the S121 well to investigate the mineral composition, pore-size distribution, and primary controls on GSC. Scanning electron microscopy and x-ray diffraction were used to observe the microscopic characteristics and identify various minerals. Nitrogen adsorption experiments at low temperatures and a methane isothermal adsorption test were conducted to study the pore sizes and gas adsorption capacities. Experimental results show that the majority of the samples were rich in type II and I kerogen with moderate to high hydrocarbon generation potential and are thermally mature in the main oil window. The contents of illite and mixed layer illite–smectite (I–S) are high (>40%) in these lacustrine mudstones. The pores were mainly thin, long, and bottleneck shaped and dominated by type IV and H2 hysteresis loop characteristics. The abundance of quartz, feldspar, illite, and mixed layer I–S all presented a positive correlation with their Brunauer–Emmett–Teller surface area and total pore volume, whereas the abundance of carbonate minerals (dominated by calcite) showed a negative correlation. The volume of micropores and clay minerals were the main factors controlling GSCs. The results highlight the importance of clay minerals, including the illite and mixed layer I–S, in the lacustrine mudstones because of their considerable GSC. High content of illite and mixed layer I–S in lacustrine mudstone is in favor of gas storage, whereas at the same time, it is not conducive to shale gas development because of its reducing the brittleness of shale. The Paleogene of Dongying depression has shale oil and gas resources; however, several key geological factors, including pore-size distributions, pore diameters, oil density, and low brittleness, may pose risks in shale oil and gas development.

Geological and geochemical characteristics of the Middle–Lower Jurassic shales in the Kuqa Depression, Tarim Basin: an evaluation of shale gas resources

ABSTRACTMiddle–Lower Jurassic terrigenous shales constitute a set of significant hydrocarbon source rocks in the Kuqa Depression of the Tarim Basin. Until recently, however, most investigations regarding this set of hydrocarbon source rocks have mainly focused on conventional oil and gas reservoirs, and little research has been conducted on the formation conditions of shale gases. This research, which is based on core samples from nine wells in the Kuqa Depression, investigated the geological, geochemical, mineralogical and porosity characteristics of the shales, analysed the geological and geochemical conditions for the formation of shale gases, and evaluated the shale gas resource potential. The results show that the distribution of the Middle–Lower Jurassic shales is broad, with thicknesses reaching up to 300–500 km. The total organic carbon (TOC) content is relatively high, ranging from 0.2 to 13.5 wt% with a mean of 2.7 wt%. The remaining hydrocarbon generative potential is between 0.1 and 22.34 mg/g, with a large range of variation and a mean value of 3.98 mg/g. It is dominated by type III kerogen with the presence of minor type II1 kerogen. The vitrinite reflectance values range from 0.517 to 1.572%, indicating the shales are in a mature or highly mature stage. The shales are mainly composed of quartz (19–76%), clay (18–68%) and plagioclase (1–10%) with mean contents of 50.36 wt%, 41.42 wt%, and 3.37 wt%, respectively. The pore spaces are completely dominated by primary porosity, secondary porosity and microfractures. The porosity is less than 10% and is mainly between 0.5 and 4%, and the permeability is generally less than 0.1 mD. These results classify the shale as a low-porosity and ultra-low-permeability reservoir. The porosity has no obvious correlation with the brittle or clay mineral contents, but it is significantly positively correlated with the TOC content. The maximum adsorbed gas content is between 0.82 and 8.52 m3/t with a mean of 3.37 m3/t. In general, the shale gas adsorption content increases with increasing the TOC content, especially when the TOC content is greater than 1.0%. The volumetric method, used to calculate the geological resources of the Middle–Lower Jurassic shales in the Kuqa Depression, shows that the geological resources of the Middle and Lower Jurassic shales reach 667.681 and 988.115 × 109 m3, respectively with good conditions for the formation of shale gas and good prospects for shale gas exploration.

The evolution of the Huangling uplift and its control on the accumulation and preservation of shale gas

ABSTRACT There are plenty of Sinian and Cambrian potential shale gas resources in South China, which is characterized by high thermal evolution degrees, poor drilling performances and only occurs in local areas. Taking the principle “high to find low” is the key issue to achieving a breakthrough in older shale. China Geological Survey drilled in the periphery of the Proterozoic basement, i.e. the Huangling anticline, in the western Hubei, and Hannan paleocontinent in the southern Shanxi. It received high-quality gas-bearing shale with relatively low Ro in the in Lower Cambrian Niutitang formation and Sinian Doushantuo formation. Based on geological conditions of shale gas reservoirs in the Huangling anticline, this paper puts forward the new model named “Control over reservoirs by periphery of basement” about shale gas accumulation, suggesting that the shale deposited in a deepwater continental shelf in the periphery of the basement is characterized by shallow burial, a short burial time, stable tectonics, relatively low thermal evolution degrees, and shale gas reservoirs in a good condition. The shale of the Sinian-Cambrian strata deposited in deepwater continental shelves in the periphery of Chuanzhong paleo-uplift in Sichuan, Hannan paleocontinent in the southern Shanxi, Huangling anticline in western Hubei and Jiangnang-Xuefeng paleo-uplift in Hunan and Guizhou province have good shale gas exploration potential.