Potential Shale Gas Reservoir Research Articles

Dual sea-level-climatic controls on the stratigraphic distribution of total organic carbon content and macerals in the Permian black shales of southwest Gondwana

The Whitehill Formation (WHF) is part of the organic-rich black shales deposited in the shallow seas that occurred within the continental interior of southwest Gondwana during the Lower Permian and has been identified as the main potential shale gas reservoir in South Africa. Here, high-resolution total organic carbon (TOC) content, organic petrographic composition, and multiple geochemical studies conducted on samples of the WHF in peak oil to gas maturity (vitrinite reflectance, Ro, range between 0.98 and 1.26%) were used to evaluate the influence of relative sea-level and climatic fluctuations on paleoproductivity, bottom-water redox condition, and clastic supply, and their combined control on the stratigraphic distribution of TOC content and macerals. Organic petrographic observations and geochemical data allowed recognition of three stratigraphic intervals (ORI-1 to ORI-3) that show marked differences in TOC content and maceral type, as well as mineralogical composition and submillimeter-to centimeter-scale sedimentary textures. TOC content increases from 0.93% at the base to 16.75% at the top. Data further revealed that the lower interval (ORI-1) is dominated by organic macerals biologically produced in the water column, including algal Tasmanites cysts, spores, and radiolaria, and depleted in land-derived macerals (inertinite, vitrinite). The mid (ORI-2) and upper ORI-3) intervals are shown to be composed of both production-derived components including bacterial biomass and aquatic plants (algae and radiolaria), as well as land-derived macerals, which are intermixed with clay-sized mineral particles, forming interconnected algal/bacterial mats. Trace and major element data indicate that these stratigraphic variations and heterogeneity of both TOC content and maceral reflect the variability of paleoproductivity, redox conditions, and clastic supply, which in turn were influenced by fluctuations of relative sea level and climate. Specifically, the accumulation of ORI-1 occurred during sea-level highstand and cool-climate, resulting in relatively higher paleoproductivity, reduced bottom-water oxygenation, and low clastic supply. However, pervasive degradation of organic matter at the seabed occasioned by low clastic detritus resulted in lower TOC content. Moreover, reduced supply of clastic detritus and severe organic matter degradation diminished the sizes of telalginite and the concentration of macerals into interconnected networks. On the contrary, intermittent decreases of relative sea-level (shallowing) and warmer conditions were detected in the mid and upper intervals, and the associated buildup of clastic sediment enhanced organic matter burial. Together these conditions resulted in higher TOC and better preservation of labile macerals. To conclude, the scale of stratigraphic heterogeneity of both TOC content and maceral type reported here may be present in many other black shale successions. Therefore, this type of study should constitute a fundamental step in the characterization of shales for their unconventional oil/gas reservoir potential.

Seismic Signature of Transition Zone (Wolf Ramp) in Shale Deposits with Application of Frequency Analysis

The concept of a transition zone, known as Wolf ramp, was incorporated into the seismic interpretation of a 3D seismic survey situated within the Baltic Basin (Northern Poland). Within the survey area, there exists one formation, the Pasłęk Formation, (Lower Silurian—Llandovery), that exhibits a linear change of velocity. This characteristic—linear change of velocity—causes a reflection coefficient (i.e., seismic amplitude) produced at such a boundary to be frequency dependent. The Pasłęk Formation was considered to be a potential shale gas reservoir and it was necessary to determine its structural position and thickness. The formation is challenging for robust seismic interpretation on the migrated seismic section—it does not manifest a stable reflection coefficient, and the amplitude contrast associated with the borders of the formation is low. There is no impedance contrast that would produce a reflection of high amplitude at the top or base of the formation which excludes determination of the formation thickness, hence the estimation of reservoir volume. Within a 3D dataset, there exists only one well with complete logs that were used for the analysis. The Pasłęk Formation is a flat-lying layer that continues itself far beyond the 3D survey. It is present in wells in the vicinity of the study area. These wells lay within other 3D or 2D datasets, but the quality of the seismic is poor, and similar seismic analysis is not possible. Nevertheless, these wells were incorporated in the research to reason about the possible link between the existence of transition zone and mineral content. The method used for recognition of transition zone is spectral decomposition and spectral analyses. The integrated studies enabled us to find a link between the Wolf ramp and mudstone-claystone interval of the Silurian age and give a new example of a transition zone which is present in shale plays. The transition zone concept might be applied for shale plays identification and analysis.

Methane sorption capacities and geochemical characterization of Paleozoic shale Formations from Western Peninsula Malaysia: Implication of shale gas potential

Thick sequences of overmatured Paleozoic black shales Formation were deposited in the Western Peninsula (WP) Malaysia, which can be considered as the potential shale gas reservoir. Therefore, to study the shale gas potential of the Paleozoic (Silurian-Permian) shale Formations, 146 samples from seven Formations were collected from WP Malaysia. A combination of methane sorption capacities, geochemical and trace element studies have been performed on the shale samples. The results indicate that the high pressure (up to 15 MPa) methane sorption capacity of the Silurian-Devonian, Devonian, Carboniferous, and Permian shales are between 0.079 and 0.154, 0.056 and 0.113, 0.052 and 0.094 and 0.085 and 0.169 mmol/g rock, respectively, at 30°C. Methane sorption capacities of the WP Malaysia shale were found to be greatly similar to sorption values of hot shales from Posidonia (Germany), Barnett (USA) and Longmaxi (China) shales. The measured total organic carbon (TOC) generally exceeded 2 wt% (average of 4 wt%), except for Carboniferous shales (>1 wt%). The biomarker analysis and Tmax values revealed that the kerogen has evolved into the metagenesis stage. The organic matter is likely comprises hydrogen-rich kerogen deposited under marine conditions in dysoxic to anoxic environment. After a comprehensive analysis, the Silurian-Devonian, Devonian and Permian shales in Western Peninsula Malaysia can be classified as potential gas shales based on their high TOC contents, presence of type III kerogen, high thermal maturity and significant methane sorption capacities.

An evaluation of empirical and rock physics models to estimate shear wave velocity in a potential shale gas reservoir using wireline logs

Shear wave velocity (Vs) is essential for determining the elastic properties of rocks, which are useful for shale gas reservoir characterization. Many investigators have developed empirical models of varying form and complexity, and simplified rock physics models for the estimation of Vs using conventional well logs and/or laboratory measurements on core samples. Other investigators have developed rock physics models and used them to estimate velocities based on fundamental rock properties such as mineralogy, pore geometry and fluid saturations. The selection of a suitable model based on well logs is challenging, especially in cases where cores are not available. This study evaluates various relationships in the literature for the estimation of shear wave velocity applied to sandy shale and shale intervals of the Lower Goru Formation, Lower Indus Basin, Pakistan. Some inputs (e.g., compressional wave velocity) are directly taken from conventional log measurements, while others (e.g., petrophysical and elastic properties) are estimated using available log and the literature data. A statistical analysis has been used to quantify the difference between measured and predicted Vs. The results reveal that some empirical models can produce a coefficient of determination (R2) of roughly 0.8 when cross-plotted against measured Vs values, and R2 values can be further increased by 10%–20% if the coefficients are adjusted based on available Vs data. However, these models do not explicitly account for the mechanisms of velocity variations in sandy shale and shale due to pore geometry (aspect ratio), consolidation and fluid saturations in the manner that rock physics models do. The rock physics modeling conducted for this work demonstrated that the use of Biot's model (rather than Gassmann's model) for fluid substitution improved model performance for Vs estimation in gas-saturated sandy shale and shale of the Lower Goru Formation. Although statistical analysis showed this model to be slightly less accurate than the best empirical models (R2 of approximately 0.77), it is suggested that the rock physics model should be reliable when applied to a broader range of saturations and lithologies in the Lower Goru Formation. Also, using the rock physics approach, model input parameters can be optimized using Vp data, which represents a significant advantage over the empirical models which require Vs data for optimization. The modified rock physics model is thus deemed to be the best option available at present for the study area, and it is suggested that it should be appropriate for use in other settings – assuming that Vp data are available and sufficient knowledge regarding rock lithology is available.

Investigation on the Potential Relationships between Geophysical Properties and CH4 Adsorption in a Typical Shale Gas Reservoir

The Longmaxi Formation is considered to be a potential shale gas reservoir in Sichuan Basin of China. In this work, 28 typical shale core samples are collected from the Longmaxi Formation and a com...

The reservoir characterization and shale gas potential of the Niutitang formation: Case study of the SY well in northwest Hunan Province, South China

Marine shale is extensive throughout the subsurface, and commercially well-developed as natural gas producers throughout south China, attracting attention in recent years by both politicians and scientists on a variety of issues. Previous research on shale has predominantly focused on the Longmaxi and Niutitang Formations in the Sichuan Basin, but rarely on the periphery in northwestern Hunan Province where the Niutitang Formation has long been known as a potential shale gas reservoir. In this study, hydrocarbon generation potential, reserving performance, and shale gas potential of the Niutitang Formation from northwestern Hunan Province was studied to determine its gas producing potential. Total organic carbon (TOC) analysis, rock-eval pyrolysis, vitrinite reflectance and organic maceral analysis, mercury intrusion, nitrogen adsorption, and methane adsorption were run on a total of 52 samples from the SY well consisting of the Upper and Lower Members of the Niutitang Formation. Analysis of the results showed that the Niutitang shale has high TOC content (2.37% on average), high thermal maturity (3.15% on average), and oil-prone kerogen types, indicating good shale gas potential in the study area. The shale consists of relatively high concentrations of brittle minerals (quartz and feldspar, 69% on average) and low clay content (22% on average), indicating a brittle shale. The shale is a tight formation, with measured porosity averaging 2.66% (free gas potential) and methane adsorption capacity averaged 1.55 cm3/g (adsorbed gas potential). TOC and burial depth control reservoir space of the shale. The Lower Member samples had lower porosity but higher methane adsorption capacity than those from the Upper Member, indicating that a relatively larger amount of gas may occur as adsorbed gas in the Lower Member. It is suggested that the Lower Member of the Niutitang Formation is the ideal location for exploration and development of shale gas due to consistently thick organic-rich layers, high TOC content, high brittleness index, and stronger adsorption capacity.

Shale gas reservoir characterization: A typical case in the Southeast Chongqing of Sichuan Basin, China.

The Lower Silurian Longmaxi Shale in Southeast Chongqing of Sichuan Basin in China is considered to be a potential shale gas reservoir by many scholars in recent years. The special shale gas well, namely, Pengye-1 well, was selected as a case study to evaluate the characteristics of the shale gas reservoir. A series of experiments were performed to analyze the geochemical, mineralogical, and petrophysical features and gas content using samples of the Longmaxi Shale from Pengye-1 well. The results show that the organic and inorganic porosities of these samples are range of 0.08–2.73% and 0.06–2.65%, with the average of 1.10% and 1.76%, respectively. The inorganic pores primarily contribute to the porosity until the TOC content is more than 3%. Organic matter plays an important role in adsorbed gas content. The adsorbed gas is dominant in the Longmaxi Shale of Pengye-1 well, which ranges from 0.46 to 2.24 cm3/g, with an average of 1.38 cm3/g. The free gas content ranges from 0.45 to 0.84 cm3/g with an average of 0.68 cm3/g, and is 24.4–49.7 percent of total gas with an average of 37.5%. The bottom part of the Longmaxi Shale is the most favorable for shale gas exploring, which is higher of brittleness mineral content, porosity and gas content. Compare with the other five shales in America, the Lower Silurian Longmaxi Shale is derived from older sedimentary periods with significantly higher thermal maturity and has experienced several periods of intense tectonic, which are unfavorable for the shale gas enrichment.

Assessing low-maturity organic matter in shales using Raman spectroscopy: Effects of sample preparation and operating procedure

Laser Raman spectroscopy is used to assess the thermal maturity of organic matter in sedimentary rocks, particularly organic-rich mudstones. However, discrepancies exist between quantified Raman spectral parameters and maturity values obtained by vitrinite reflectance. This has prevented the adoption of a standard protocol for the determination of thermal maturity of organic matter (OM) by Raman spectroscopy. We have examined the factors influencing the Raman spectra obtained from low-maturity OM in potential shale gas reservoir rocks. The inconsistencies in Raman results obtained are due to three main factors that are critically evaluated: (1) different operational procedures, including experiment setup and spectral processing methods; (2) different methods of sample preparation; (3) the analysis of diverse types of OM. These factors are scrutinized to determine the sources of inconsistency and potential bias in Raman results, and guidance is offered on the development of robust and reproducible analytical protocols. We present two new Raman parameters for un-deconvolved spectra named the DA1/GA ratio (area ratio of 1100–1400 cm−1/1550–1650 cm−1) and SSA (scaled spectrum area: sum of total area between 1100 and 1700 cm−1) that offer potential maturity proxies. An automated spreadsheet procedure is presented that processes raw Raman spectra and calculates several of the most commonly used Raman parameters, including the two new variables.

Feasibility of ASD AgriSpec Analysis to Indicate Mineralogy of a Potential Shale Gas Reservoir from West Lancashire, UK

Mudrocks rich in organic matter present an attractive exploration target for unconventional gas and oil. The mid-Carboniferous Bowland Shale is considered the principal accumulation of gas-prone shales in the UK. One risk with exploitation of shales is that the rocks may exhibit ductile behaviour and not respond well to hydraulic stimulation programmes. The brittle behaviour of the rock is influenced by mineralogical composition. Approximately 15 m of core from the Bowland Shale, has been used to test the feasibility of using Near Infra-Red (NIR) Spectrometry to characterise the mineralogy of the shale, and compare to analysis using standard XRD techniques.

Novel 3D centimetre-to nano-scale quantification of an organic-rich mudstone: The Carboniferous Bowland Shale, Northern England

X-ray computed tomography and serial block face scanning electron microscopy imaging techniques were used to produce 3D images with a resolution spanning three orders of magnitude from ∼7.7 μm to 7 nm for one typical Bowland Shale sample from Northern England, identified as the largest potential shale gas reservoir in the UK. These images were used to quantitatively assess the size, geometry and connectivity of pores and organic matter. The data revealed four types of porosity: intra-organic pores, organic interface pores, intra- and inter-mineral pores. Pore sizes are bimodal, with peaks at 0.2 μm and 0.04 μm corresponding to pores located at organic–mineral interfaces and within organic matter, respectively. These pore-size distributions were validated by nitrogen adsorption data. The multi-scale imaging of the four pore types shows that there is no connected visible porosity at these scales with equivalent diameter of 20 nm or larger in this sample. However, organic matter and clay minerals are connected and so the meso porosity (<20 nm) within these phases provides possible diffusion transport pathways for gas. This work confirms multi-scale 3D imaging as a powerful quantification method for shale reservoir characterisation allowing the representative volumes of pores, organic and mineral phases to be defined to model shale systems. The absence of connected porosity at scales greater than 20 nm indicates the likely importance of the organic matter network, and associated smaller-scale pores, in controlling hydrocarbon transport. . The application of these techniques to shale gas plays more widely should lead to a greater understanding of properties in the low permeability systems.

Characterization of the Lower Cambrian Shale in the Northwestern Guizhou Province, South China: Implications for Shale-Gas Potential

The Lower Cambrian shale in the Northwest part of the Guizhou Province (NWG), South China, has recently been considered as a potential shale gas reservoir because of its large distribution and high total organic carbon (TOC) content. An integrated characterization about this shale succession is provided in this study to illustrate its shale gas potential. The shale in the NWG area is characterized by high TOC content and high thermal maturity. The mineralogical composition and lithofacies assemblage of the NWG shale are compared with hot shales for analogy and found to be greatly similar to the Barnett shales. Five different genetic types of pores have been identified by scanning electron microscopy. The porosity shows no correlation with the quartz and clay ratios, but it correlates well with the TOC content, suggesting that organic matter pores have contributed a lot to the total porosity. The pore size distribution is evaluated by pore volume and surface area based on diameter, indicating that the micr...

Evaluation of Lower Cambrian Shale in Northern Guizhou Province, South China: Implications for Shale Gas Potential

The Lower Cambrian shale is an important source rock for conventional oil and gas in northern Guizhou province (NGP), south China, but has recently been considered as a potential shale gas reservoir. In this study, characterization of this target shale was determined through a systematic series of measurements on core samples. According to total organic carbon (TOC) and Rock-Eval data, the Lower Cambrian shale is overmature but still contains high amounts of organic matter, which is composed mainly of alginite. The TOC content is enriched up to 10.4% at the base of the shale. There are two different correlation patterns between trace elements and TOC in the Lower Cambrian shale. A good correlation present in the upper part indicates a non-sulfidic anoxic sedimentary environment. However, higher enrichments of U, V, and Mo in the basal part exhibit sulfidic euxinic conditions. Brittle minerals are quite abundant and have a critical effect on artificial fracture. Gas sorption volume increases with an increasing TOC, pore volume, and surface area, indicating that pores at the microscale associated with the organic matter fraction are an important control on storage capacity. The contribution of clay minerals to the sorbed gas may be irrelevant because of the presence of moisture. Analysis of data indicates that the basal part of the Lower Cambrian shale demonstrates the greatest potential for gas content and can be explored for production.

Shale gas reservoir characterisation: A typical case in the southern Sichuan Basin of China

The Lower Silurian Longmaxi Formation is an organic-rich (black) mudrock that is widely considered to be a potential shale gas reservoir in the southern Sichuan Basin (the Yangtze plate) in Southwest China. A case study is presented to characterise the shale gas reservoir using a workflow to evaluate its characteristics. A typical characterisation of a gas shale reservoir was determined using basset sample analysis (geochemical, petrographical, mineralogical, and petrophysical) through a series of tests. The results show that the Lower Silurian Longmaxi Formation shale reservoir is characterised by organic geochemistry and mineralogical, petrophysical and gas adsorption. Analysis of the data demonstrates that the reservoir properties of the rock in this region are rich and that the bottom group of the Longmaxi Formation has the greatest potential for gas production due to higher thermal maturity, total organic carbon (TOC) enrichment, better porosity and improved fracture potential. These results will provide a basis for further evaluation of the hydrocarbon potential of the Longmaxi Formation shale in the Sichuan Basin and for identifying areas with exploration potential.