Over-mature Shales Research Articles

Pore size distributions contributed by various components in the Upper Ordovician Wufeng Shale from Southeast Chongqing, China

To quantitatively evaluate the pore size distributions (PSD) contributed by various components (PSDCVC) in over-mature shale samples, the Upper Ordovician Wufeng Shale from Southeast Chongqing was taken as an example. The PSDCVC model was established using the experimental results including total organic carbon (TOC), carbon element content in organic matter (OM), X-ray diffraction mineral composition analysis and low-pressure N2 adsorption/desorption (LPNA) tests, which were performed on three sets of subsamples. The PSDs associated with OM, clay, other components and shale sample per unit mass were obtained, and the PSDs of the subsamples calculated from PSDCVC method were compared with the results of LPNA and field emission scanning electron microscopy methods to confirm the credibility of PSDCVC results. For the shale samples from the same layer, the pore volumes (PV) of different pore widths associated with OM, clay and other components per unit mass are corresponding constants or similar to these constants, respectively. The PSDs associated with OM, clay and other components are primarily distributed in the pore widths of <5 nm, 20–100 nm and 10–100 nm, respectively. The PVs of pore widths <200 nm contributed by OM, clay and other components per unit mass are 1830.52 × 10−4 cm3/g, 29.52 × 10−4 cm3/g and 0.05 × 10−4 cm3/g, respectively. In the shale samples per unit mass, the average PVs of pore widths <200 nm contributed by OM, clay and other components are 49.16 × 10−4 cm3/g, 7.89 × 10−4 cm3/g and 0.04 × 10−4 cm3/g, representing contributed proportions of 85.80%, 14.14% and 0.06%, respectively. The PVs of pore widths <200 nm in the Wufeng Shale sample with TOC content >0.22% is mainly contributed by OM.

Mineralogical and petrographic characteristics of the Ordovician-Silurian Wufeng-Longmaxi Shale in the Sichuan Basin and implications for depositional conditions and diagenesis of black shales

Depositional and diagenetic processes play important roles in controlling the fabric and petrophysical properties of black shales. In this study, an outcrop section of the Wufeng-Longmaxi Shale was studied through sedimentologic facies analysis, petrographic observations (both transmitted- and reflected-light microscopy and scanning electron microscopy), and X-ray diffraction analysis to investigate how depositional and diagenetic processes controlled the accumulation and evolution of organic-rich black shales. The studied Wufeng-Longmaxi Shale consists of over-mature black shales, with an equivalent vitrinite reflectance of 3.07%. Organic matter is dominated by pyrobitumen and graptolite, the former of which hosts abundant organic pores. Minerals mainly consist of quartz (average 42 wt %), carbonates (average 37.4 wt %), and clay minerals (average 15 wt %). Eighty percent of quartz is of biogenic origin, which occurs as siliceous fossils and microcrystalline quartz. Microcrystalline quartz forms a rigid framework and preserves organic pores from compaction. Clay minerals comprise dominantly (95 wt %) illite and mixed-layer illite/smectite. The vertical variations in lithofacies and quartz and carbonate mineral content exhibit three cycles, likely corresponding to three transgressive-regressive cycles. Within each cycle, quartz content first increases to reach a maximum at the maximum flooding surface, and then decreases. Although long being considered as deposited under quiescent and anoxic conditions, sedimentologic and petrographic analyses in this study indicate that the deposition of the Wufeng Formation and lower Longmaxi Formation was subject to intermittent reworking by bottom currents and bottom-water dysoxia. Meiofauna capable of tolerating low oxygen content could have lived in surficial sediments and disrupted the original fabric of sediments formed by bottom currents. Mineralogical and petrographic analyses in this study provide new insights into the accumulation mechanism of the organic-rich black shales of the Wufeng-Longmaxi Formations, calling for a critical reappraisal of other black shales that have conventionally been considered as deposited under mostly quiet and anoxic conditions. • Mineralogical and petrographic characteristics were studied. • Three stratigraphic cycles were identified. • Depositional conditions were not persistently quiescent and anoxic. • Intermittent reworking by bottom currents and bottom-water dysoxia existed.

Machine Learning Method for TOC Prediction: Taking Wufeng and Longmaxi Shales in the Sichuan Basin, Southwest China as an Example

The total organic carbon content (TOC) is a core indicator for shale gas reservoir evaluations. Machine learning-based models can quickly and accurately predict TOC, which is of great significance for the production of shale gas. Based on conventional logs, the measured TOC values, and other data of 9 typical wells in the Jiaoshiba area of the Sichuan Basin, this paper performed a Bayesian linear regression and applied a random forest machine learning model to predict TOC values of the shale from the Wufeng Formation and the lower part of the Longmaxi Formation. The results showed that the TOC value prediction accuracy was improved by more than 50% by using the well-trained machine learning models compared with the traditionalΔLogRmethod in an overmature and tight shale. Using the halving random search cross-validation method to optimize hyperparameters can greatly improve the speed of building the model. Furthermore, excluding the factors that affect the log value other than the TOC and taking the corrected data as input data for training could improve the prediction accuracy of the random forest model by approximately 5%. Data can be easily updated with machine learning models, which is of primary importance for improving the efficiency of shale gas exploration and development.

Bedding-parallel calcite veins indicate hydrocarbon–water–rock interactions in the over-mature Longmaxi shales, Sichuan Basin

Bedding-parallel calcite veins in shales archive hydrocarbon–water–rock interactions, but such processes in highly–over mature shales are poorly understood in terms of their geological and geochemical significance. To fill the knowledge gap, we conducted a combined petrographic, geochemical, isotopic, and fluid inclusion study of the Silurian Longmaxi Formation in the Sichuan Basin, China, to investigate these processes. Our results show that bedding-parallel calcite veins grow nearly vertically along the median plane, and exhibit antitaxial and two stages of growth. The early calcite veins have high δ13C values (0.08‰–4.75‰) and the diagenetic fluids were relatively low-temperature (120–150 °C) and high-salinity (11.2%), and formed during primary migration of hydrocarbon-bearing fluids in the oil window. The late calcite veins have relatively low δ13C values (−7.01‰ to −0.08‰) and the diagenetic fluids were high-temperature (180–210 °C) and low-salinity (8.9%), and formed in the gas window. The similar 87Sr/86Sr and δ13C values of the calcite veins and surrounding host rocks, combined with the relatively uniform fluid δ18OV-SMOW values, indicate that the calcite-precipitating fluids were derived mainly from the surrounding host-rocks and organic fluids. The formation of bedding-parallel calcite veins records the two-stage, fluid-overpressured evolution of organic matter in the oil and gas generation stages.

Pore characterization of the Marcellus Shale by nitrogen adsorption and prediction of its gas storage capacity

In a shale gas reservoir, pore characterization is an important factor used to determine gas storage capacity. However, the nanometer (nm)-scale pore system in shale is difficult to explore by traditional optical, scanning electron microscopy, or even nuclear magnetic resonance well logging. We have investigated the pore structure and storage capacity of the Marcellus Shale through integration of petrophysical analysis from laboratory and well-logging data and nitrogen adsorption. The isotherm of Marcellus Shale is a composite isotherm, which has features of type I, type II, and type IV isotherms with type H4 of the hysteresis loop, suggesting slit-like pores developed in the Marcellus Shale. Quantitative analysis of pore volumes from the nitrogen adsorption indicates that density porosity may be more properly used to approximate the shale porosity and estimate the shale gas volume. In addition, the specific surface area, micropore, and mesopore volumes have a positive relationship with the kerogen volume and total organic content (TOC). By using the Langmuir and Brunauer-Emmet-Teller models, the simulated result indicates that the higher adsorbed quantity of the Marcellus Shale could be the result of the increase of micropore volume contributed, by the increase of kerogen or TOC content. The proposed equations rapidly compute TOC, a key parameter to predict gas storage capacity in overmature shale such as the Marcellus Shale.

A composition-based model for methane adsorption of overmature shales in Wufeng and Longmaxi Formation, Sichuan Basin

The Wufeng-Longmaxi Formation shale in Sichuan Basin is the main strata of shale gas exploration and development in China. Adsorbed methane is an important part of the total shale gas content. The influence of shale composition on adsorption characteristics is complex, and it is difficult to obtain a comprehensive understanding without a sufficient amount of data. In this work, the total organic carbon (TOC), X-ray diffraction (XRD) mineral analysis, and the excess methane adsorption isotherms with pressure up to 50 MPa at 40 °C of 106 overmature shale samples with TOC of 0.8%-9.0% and clay content of 2%-58% that belong to Wufeng-Longmaxi formation from 10 shale gas wells in Sichuan Basin, China are experimentally investigated and analyzed. New correlations found between compositions and methane adsorption characteristic parameters guide the establishment of a composition-based methane adsorption model that the excess adsorption isotherm of shale is the content-weighted sum of equivalent unit-content excess isotherms for organic matter and clay. With this model, the differences of excess isotherms of these two compositions and the differences of clay-contribution to methane adsorption for different sublayers are disclosed. It is beneficial to improve the accuracy of shale reservoir evaluation of studied blocks under the condition of limited coring and deepening the understanding of the underlying mechanism of methane adsorption characteristics.

Petrographic Characterization and Maceral Controls on Porosity in Overmature Marine Shales: Examples from Ordovician-Silurian Shales in China and the U.S.

The pore structure characterization and its controlling factors in overmature shales are keys to understand the shale gas accumulation mechanism. Organic matter in source rocks is a mixture of various macerals that have their own specific evolutionary pathways during thermal maturation. Pores within macerals also evolve following their own path. This study focused on petrographic characterization and maceral controls on porosity in overmature marine shales in China and the United States. Shale from Ordos Basin in China was also selected as an example of overmature transitional shale for maceral comparison. Organic petrology techniques were used to identify maceral types and describe morphological features in detail; scanning electron microscopy techniques were then used to document the abundance and development of pores within macerals. Helium measurement, mercury intrusion capillary pressure, and CO2 adsorption were especially applied to quantify the pore structure of Wufeng-Longmaxi shale from Sichuan Basin in China. The vitrinite reflectance equivalent of the studied overmature samples is ~2.4%. The macerals within the studied marine shales are composed mainly of pyrobitumen and zooclasts. At this maturity, pyrobitumen develops abundant gas-related pores, and their volume positively correlates to gas content. Three types of pyrobitumen and its related pore structure are characterized in Wufeng-Longmaxi shales. Zooclasts contribute to total organic carbon (TOC) content but little to porosity. When the TOC content is above 1.51% in Wufeng-Longmaxi samples, the TOC content positively correlates to quartz content. Organic matter strongly controls micropore development. Pores of diameter ~ 0.5 nm provide a significant amount of micropore volume. Clay mineral and quartz contents control micro- and macropore increments in organic-lean shales. MICP results indicate that pores within 3-12 nm and 900-2500 nm account for a major contribution to pore volume obtained. Determining the proportions of pyrobitumen to zooclasts within the total organic matter in pre-Devonian organic-rich marine shales is important in predicting porosity and gas storage capacity in high-maturity shales.

Pore formation and evolution of organic-rich shale during the entire hydrocarbon generation process: Examination of artificially and naturally matured samples

Shale pore type and variation have significant influences on natural gas storage and are of vital importance for shale gas resource evaluation. To better understand the formation and evolution of shale pores during hydrocarbon generation process, organic geochemistry, X-ray diffraction, field emission scanning electron microscopy (FE-SEM), and low-pressure nitrogen gas adsorption (N2GA) were applied to samples created by thermal simulation and to naturally evolved samples of the Upper Permian Dalong Formation in the northwestern Sichuan Basin. The results show that the development of organic matter (OM) pores is controlled by kerogen type and thermal maturation level and begins at equivalent vitrinite reflectance (eqvRo) value of 0.91%. Two types of OM pores are developed during OM evolution stage, as bubble pores that are formed at the oil window stage and spongy pores which occcur at the dry gas stage. Maximum pore volume, particularly mesopore volume, occurs within two opportune development periods with the corresponding eqvRo values of 1.11–1.53% and 2.5–2.9%, respectively. The periods are known to be the two peak stages of shale pore development. The first peak corresponds to the late oil generation stage, and the second corresponds to the cracking peak of extractable OM to gas, during which numerous OM micropores and mesopores are generated. OM pore generation is generally resulted from OM decomposition, and pore structure parameters exhibit significant positive correlations with OM reduction for simulated samples. For naturally matured samples, TOC content is positively correlated with pore structures. Extractable OM generated from primary kerogen fills OM pores and mineral-related pores and further reduces shale pore volume. In terms of analysis on naturally matured samples with similar maturities, OM pores in type II1 kerogen are inferior to those in type I kerogen but more developed than those in type III kerogen. Shale pore evolution is also controlled by diagenesis. Compaction and cementation have adverse effects on shale pore preservation during early and late diagenesis stages, which leads to a significant decrease in shale pore volume, particularly that of mesopores. It should be noted that OM pores are better developed and preserved even when the eqvRo value exceeds 3.25%, which is of vital importance for extending the field of shale gas exploration of over-mature shale reservoirs.

Experimental Gas Generation of Organic-Rich Shales at Different Oil Expulsion Efficiencies: Implications for Shale Gas Evaluation

The assessment of the gas generation potential of highly to overmature shale is key for shale gas evaluation, but it is always fraught with challenges. In this study, immature shale samples with ty...

Using rock-eval S4Tpeak as thermal maturity proxy for shales

The Rock-Eval pyrolysis-stage derived parameters such as free hydrocarbons (S1), heavier pyrolysis-hydrocarbons (S2), pyrolyzable carbon (PC) and pyrolysis Tmax (from S2 curve) have received considerable interest for source-rock screening and thermal maturity assessment. On the other hand, the Rock-Eval oxidation-stage S4CO2 curve, which gives the amount of residual carbon (RC), only recently has received some interest. While the pyrolysis-stage S2 temperature-peak (Tmax) is conventionally used as a maturity proxy, in this work we show that the temperature-peak of S4CO2 curve (S4Tmax) can also be used as a thermal maturity proxy for shales. For overmature and low-TOC shale samples, showing asymmetric S2 shape and concomitantly producing doubtful Tmax, the S4 curves showed symmetric nature and consequently the S4Tmax was observed to be a reliable thermal maturity estimate. While the S4Tmax clearly resolved immature and overmature shales, for the early mature and peak mature shales the S4Tmax showed overlapping values. S4Tmax of pre-pyrolyzed and pyrolyzed masses showed good positive correlation with differential scanning calorimetry temperature-peak (DSCTpeak), and consequently indicated its applicability as a thermal maturity proxy. When early mature pre-pyrolyzed samples were directly analyzed using the Rock-Eval oxidation stage, the S4 curves showed formation of two sub-peaks, and consequently the Tmax was observed to decrease. It is recommended that analysts and interpreters should thoroughly cross-check S2 curves before reporting data, and in case of asymmetric or unreliable S2 curves, the S4Tmax can be used as a maturity proxy.

Controls of Distinct Mineral Compositions on Pore Structure in Over-Mature Shales: A Case Study of Lower Cambrian Niutitang Shales in South China

Investigating the impacts of rock composition on pore structure is of great significance to understand shale gas occurrence and gas accumulation mechanism. Shale samples from over-mature Niutitang formation of Lower Cambrian in south China were measured by X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), low pressure N2 and CO2 adsorption to elucidate the controls of distinct mineral composition on pore development. Two distinct lithofacies, namely siliceous shale and argillaceous shale, were ascertained based on their mineral composition. Due to the variability of mineral composition in different lithofacies, pore structure characteristics are not uniform. Pores in siliceous shales are dominated by interparticle pores and organic matter (OM) pores, among which the interparticle pores are mainly developed between authigenic quartz. Furthermore, most of these interparticle pores and cleavage-sheet intraparticle pores within clay minerals are usually filled by amorphous organic matter that is host to OM pores. Due to the lack of rigid minerals, argillaceous shale was cemented densely, resulting in few interparticle pores, while cleavage-sheet intraparticle pores within clay minerals are common. Comparing siliceous shales with argillaceous shales, specific surface areas and pore volumes are higher on the former than on the latter. The content of total organic carbon (TOC) and authigenic quartz have a great influence on micropore structures, but less on mesopore structure for siliceous shales. The rigid framework structure formed by authigenic quartz is believed to be able to prevent primary interparticle pores from mechanical compaction and facilitate the formation of organic matter-associated pores. In terms of argillaceous shales, due to the lack of authigenic quartz, interparticle pores were rarely developed and its pore structure is mainly controlled by illite content.

Elemental geochemistry proxies recover original hydrogen index values and total organic carbon contents of over-mature shales: Lower Cambrian South China

The determination of the original organic matter type and content of source rock in over-mature petroleum systems is critical for accurately evaluating the original hydrocarbon-generation capacity, but has challenged researchers for decades. Here we present a new method for such analyses using inorganic geochemistry, which was applied to a case study of over-mature shales of the Lower Cambrian Niutitang Formation (Upper Yangtze region, South China). Multiple redox proxies (e.g., VEF, UEF, MoEF, and Th/U ratio) indicate that the Lower and Upper members were deposited under anoxic bottom water and suboxic conditions, respectively. This implies different proxies suitable for recovering the original hydrogen index (HIo) values, i.e., CuXS and Porg for the Lower (anoxic) and Upper (suboxic) members, respectively. Then, the original total organic carbon (TOCo) content of the shales were calculated by using the formula TOCo = (TOCpd – (S1+S2) ×0.085 – HIo × 0.0004)/(1 – HIo/1177), of which TOCpd refers to the measured present-day TOC data and S1 and S2 are the Rock-Eval pyrolysis hydrocarbons. Excellent original hydrocarbon generation capacity was revealed in that HIo and TOCo are 600–893.4 mg hydrocarbon (HC)/g TOC (average = 758.4) and 0.2–32.2 wt% (average = 10.2), respectively. Combined with six lithofacies identified from mineralogy and petrology, heterogeneities of the hydrocarbon-generation potential in different lithofacies of the Niutitang Formation shales of this study were revealed. The laminated siliceous shale and laminated carbonaceous shale facies had higher HIo and TOCo than the other facies, and can thus be regarded as the lithofacies with the highest hydrocarbon-generation potential. Our study provides a new method using inorganic geochemistry to restore the original kerogen type and TOC content of over-mature shales with a high degree of accuracy, which can be used to robustly evaluate the hydrocarbon generation potential of conventional and unconventional hydrocarbon resources in over-mature source rocks.

Effect of Particle Size on Pore Characteristics of Organic-Rich Shales: Investigations from Small-Angle Neutron Scattering (SANS) and Fluid Intrusion Techniques

The sample size or particle size of shale plays a significant role in the characterization of pores by various techniques. To systematically investigate the influence of particle size on pore characteristics and the optimum sample size for different methods, we conducted complementary tests on two overmature marine shale samples with different sample sizes. The tests included small-angle neutron scattering (SANS), gas (N2, CO2, and H2O) adsorption, mercury injection capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging. The results indicate that artificial pores and fractures may occur on the surface or interior of the particles during the pulverization process, and some isolated pores may be exposed to the particle surface or connected by new fractures, thus improving the pore connectivity of the shale. By comparing the results of different approaches, we established a hypothetical model to analyze how the crushing process affects the pore structure of overmature shales. Our results imply that intact wafers with a thickness of 0.15–0.5 mm and cubic samples (~1 cm3) are optimal for performing SANS and MICP analyses. Meanwhile, the 35–80 mesh particle size fraction provides reliable data for various gas physisorption tests in overmature shale. Due to the intrinsic heterogeneity of shale, future research on pore characteristics in shales needs a multidisciplinary approach to obtain a more comprehensive, larger scale, and more reliable understanding.

Characterization of methane adsorption on shale of a complex tectonic area in Northeast Guizhou, China: Experimental results and geological significance

Complex tectonic settings are generally considered to be unfavorable for shale gas accumulation, but a favorable desorption-gas content has been detected in Lower Cambrian Lujiaping Shales in Dabashan fold-thrust belt in northeastern Chongqing, Southern China, which suggests a good exploration potential. High-pressure (~30 MPa) and high-temperature (~120 °C) (HP-HT) methane adsorption isotherms were conducted on seven samples collected at 2665–2707 m below the ground surface from the Lower Cambrian Niutitang Shale (equivalent to the Lujiaping Shale) from northeast Guizhou Province, Southern China to assess methane adsorption capacity and the influence of total organic carbon (TOC) content, thermal maturity, mineralogy, and temperature-pressure conditions on methane adsorption in over-mature shales in complex tectonic areas. The samples contain high TOC contents, ranging from 5.1% to 8.4%, and equivalent vitrinite reflectance Ro values ranging from 3.62% to 3.85%. Over the experimental pressure range up to 30 MPa, Langmuir volumes correlate positively with TOC contents, which may be related to the increase in specific surface area and micropores (<2 nm) volume with an increasing TOC content. Organic matter (OM)-hosted micropores and nanometer-sized intergranular pores in clay-OM nanocomposites mostly contribute to the adsorption capacity of this over-mature Niutitang Shale. In addition, the different behaviors of other minerals (quartz, carbonate and illite) under intensive tectonic compression also affect the adsorption capacity of shales. Due to the low porosity of the Niutitang Shale, the free gas content in these samples is relatively low, and the adsorbed gas always makes up the majority of gas-in-place (GIP), hence the “equivalent point” of adsorbed gas and free gas does not exist at depths of <6 km. This suggests that the shallow (<3 km) Niutitang Shale should be primarily targeted for adsorbed gas under low-temperature and high-pressure geological conditions.

The characteristics and developmental control factors of microscopic pore structure in shale gas reservoirs in the Lower Cambrian Qiongzhusi Formation

The Early Cambrian Qiongzhusi Formation on the southern margin of the Sichuan Basin (Southern China) has experienced a long geological process. High degree of thermal evolution of the organic matter shows a great impact on the organic evolution, reservoir microscopic pore types and structure characteristics in this formation. In this study, we investigate the major types and structural features of microscopic pores in shale gas reservoirs of the Qiongzhusi FM. Different types of matrix pores are found, over-mature shale gas reservoirs in the Qiongzhusi FM. mainly have well-developed micropores, but their average specific surface area (SSA) and pore volume are smaller than those in the Longmaxi Formation. The degree of thermal evolution poses the greatest impact on microscopic pore structure, which is significantly positively correlated with SSA and pore volume; however, when exceeding this range, SSA and pore volume both drastically decrease with increasing degree of thermal evolution. Compared with those in the Longmaxi FM., microscopic pores of shale gas reservoirs in the Qiongzhusi FM. feature pore- SSA and large surface porosity. The better the development of micropores, the larger the SSA and Vp of shales, which are more conducive to shale gas adsorption and accumulation.

Pore size distributions contributed by OM, clay and other minerals in over-mature marine shale: A case study of the Longmaxi shale from Southeast Chongqing, China

Nano-scale pores play an important role in determining the adsorption capacity of shale gas. To quantitatively evaluate the pore size distributions contributed by organic matter (OM), clay and other minerals in an over-mature shale reservoir, the Lower Silurian Longmaxi shale from Southeast Chongqing was selected as a case study and was analyzed by the pore size distributions contributed by OM, clay and other minerals (PSDCOCO) method. Based on the results of total organic carbon (TOC), carbon element content in OM, X-ray diffraction (XRD) and low temperature nitrogen adsorption/desorption (LTNA) experiments, the pore size distributions contributed by a unit mass of OM, clay and other minerals were calculated and the differences between the results of the LTNA and PSDCOCO methods were determined for the four verified samples. The average value of the difference between the experimental and calculated pore volumes is 0.154 × 10−3 cm3/g. For the Longmaxi shale from the Py1 well, the contributions of OM and other minerals to the pore volume (pore width <200 nm) are primarily distributed in the pore width ranges from 2 to 20 nm and <2 nm, respectively. The nano-scale pore size distributions (<200 nm) contributed by the clay minerals have two relatively high peak values in the pore width ranges of 20–100 nm and 2–5 nm. The pore volumes for pore widths less than 200 nm contributed by a unit mass of OM, clay and other minerals were 115.776 × 10−3 cm3/g, 10.489 × 10−3 cm3/g and 0.006 × 10−3 cm3/g, respectively. In the shale reservoir, the contributions of OM, clay and other minerals to the pore volume with pore widths less than 200 nm were 45.75%, 54.17% and 0.08%, respectively, based on the limited data available.

Precise maturity assessment over a broad dynamic range using polycyclic and heterocyclic aromatic compounds

The construction and reliable application of maturation indices is extremely important in deep Earth exploration, yet predicting levels of maturation on a molecular level, especially at overmature stages, is still a major challenge. Here, we report robust, broad ranging and precise maturity parameters that were developed using a continuous core of thermally overmature lacustrine deposits (Shahezi Fm.) from the deep Songke-2 Well (SK-2), Songliao Basin, China, augmented by shallow cores of lower maturity marine deposits (Posidonia Shale) from the Hils Syncline, Germany.The novel indices presented here are based on the general process of thermally-induced cyclization, aromatization and aliphatic chain cracking of hundreds to thousands of compounds during maturation. The newly developed parameters, with an extremely broad dynamic range extending from catagenesis and into metagenesis (vitrinite reflectances (Ro) range from 0.9% to 2.2%), are based on polycyclic and heterocyclic aromatic compounds measured using Fourier transform-ion cyclotron resonance-mass spectrometry (FT-ICR-MS). The high coefficient of correlations between the new maturity parameters with Ro and Tmax demonstrate their utility for assessing precisely the thermal maturity of overmature shales.

Experimental investigation of water vapor adsorption isotherm on gas-producing Longmaxi shale: Mathematical modeling and implication for water distribution in shale reservoirs

Mathematical characterization of water vapor adsorption (WVA) isotherms on organic-rich shale is important for both modeling processes such as water flow and mass transport, and accurate evaluation of moisture content in shale. Although several theoretical and empirical models have been proposed to describe WVA on porous materials (e.g, coal, food and carbon black), the applicability of these proposed models for over-mature gas shale (e.g., >2.0%Ro) is not well understood, which requires both experimental data and a theoretical description of downhole shale. In this work, WVA isotherms were measured at 50℃ (323.1 K) using a dynamic vapor sorption apparatus for four over-mature Lower Silurian Longmaxi shales, the leading gas-producing shale reservoir in the Sichuan Basin, China. To describe water adsorption behavior mathematically, five models, including the Guggenheim-Anderson-de Boer (GAB), double log polynomial (DLP), Oswin, Freundlich, and Frenkel-Halsey-Hill (FHH), for WVA isotherm are evaluated for their ability to match the experimental WVA isotherm data.In general, all the models are suitable for fitting the experimental data, with R2 values larger than 0.95. However, the transformations of non-linear isotherm equations to their linear forms could implicitly alter the error structure and may violate the error variance and normality assumptions. To address this deficiency, six more statistical parameters (AAD, MSE, SEE, RSS, ARE and χ2) were used to evaluate the goodness-of-fit results for different models. Comparative studies show that the four-parameter DLP model is the optimal to predict the WVA isotherms on Longmaxi shale, with the smallest fitting errors, rather than the most versatile GAB model documented in the literature. Considering the WVA behavior, the distribution of water (free and adsorbed) in hydrophobic and hydrophilic pores in shales was also discussed, which can provide a reference point for theoretical analysis of water flow and retention.

Pore anisotropy in unconventional hydrocarbon source rocks: A small-angle neutron scattering (SANS) study on the Arthur Creek Formation, Georgina Basin, Australia

Small-angle neutron scattering (SANS) measurements were performed on 32 rock samples from the southern Georgina Basin, central Australia to assess nanopore anisotropy. Anisotropy can only be determined from oriented core material, hence the samples were cut perpendicular to bedding in cores selected from three wells that intersect the base of the hydrocarbon-bearing, organic-rich middle Cambrian Arthur Creek Formation; the latter is the source rock for both unconventional and conventional plays in the basin. The evolution of anisotropy of two-dimensional SANS intensity profiles with depth (for pore diameters ranging from 10 nm to 100 nm) was quantified and correlated with SANS intensity and total organic carbon (TOC) content. Our results confirm hydrocarbon generation at the base of the Arthur Creek Formation in the wells analysed. The nanopore anisotropy in the basal Arthur Creek Formation at the well locations CKAD0001 (oil generation window) and MacIntyre 1 (late oil generation window) varies roughly according to normal compaction. When the Arthur Creek Formation is in the gas window, as sampled at Baldwin 1, there is a strong (negative) correlation between the average vertical-to-horizontal pore shape anisotropy and SANS intensity. The results indicate that unconventional gas production from organic-rich regions of overmature shale may be adversely affected by abnormal pore compaction.

Supercritical Methane Adsorption on Overmature Shale: Effect of Pore Structure and Fractal Characteristics

To investigate supercritical methane adsorption on shale and its controlling factors, high-pressure (up to 20 MPa) methane adsorption experiments were performed on overmature Niutitang shales from ...