Shale Gas-in-Place Calculation from Sichuan Basin, China

2013 ◽  
Vol 803 ◽  
pp. 342-346
Author(s):  
Hua Qing Xue ◽  
Hong Ling Liu ◽  
Gang Yan ◽  
Wei Guo
Keyword(s):  
Shale Gas ◽  
Sichuan Basin ◽  
Water Saturation ◽  
Organic Content ◽  
Gas Content ◽  
High Porosity ◽  
Formation Pressure ◽  
Free Gas ◽  
Gas Accumulation ◽  
Content Measurement

The methods of shale gas content measurement and shale Gas-in-place calculation are introduced in detail. The shale gas content is form 1.05 to 1.84 m3/t. From Gas-in-place calculation the adsorption gas content is a little more than free gas content. The advantage of shale gas accumulation areas are high formation pressure, low water saturation, high porosity and high total organic content. There are some discrepancy between shale gas content testing and gas in place calculation and three reasons may cause this phenomenon.

scholarly journals Coupling between Source Rock and Reservoir of Shale Gas in Wufeng-Longmaxi Formation in Sichuan Basin, South China

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2679
Author(s):  
Yuying Zhang ◽  
Shu Jiang ◽  
Zhiliang He ◽  
Yuchao Li ◽  
Dianshi Xiao ◽  
...  
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Sichuan Basin ◽  
Gas Content ◽  
Potential Zone ◽  
Hydrocarbon Generation ◽  
Gas Generation ◽  
Longmaxi Formation ◽  
Siliceous Shale ◽  
Organic Pores

In order to analyze the main factors controlling shale gas accumulation and to predict the potential zone for shale gas exploration, the heterogeneous characteristics of the source rock and reservoir of the Wufeng-Longmaxi Formation in Sichuan Basin were discussed in detail, based on the data of petrology, sedimentology, reservoir physical properties and gas content. On this basis, the effect of coupling between source rock and reservoir on shale gas generation and reservation has been analyzed. The Wufeng-Longmaxi Formation black shale in the Sichuan Basin has been divided into 5 types of lithofacies, i.e., carbonaceous siliceous shale, carbonaceous argillaceous shale, composite shale, silty shale, and argillaceous shale, and 4 types of sedimentary microfacies, i.e., carbonaceous siliceous deep shelf, carbonaceous argillaceous deep shelf, silty argillaceous shallow shelf, and argillaceous shallow shelf. The total organic carbon (TOC) content ranged from 0.5% to 6.0% (mean 2.54%), which gradually decreased vertically from the bottom to the top and was controlled by the oxygen content of the bottom water. Most of the organic matter was sapropel in a high-over thermal maturity. The shale reservoir of Wufeng-Longmaxi Formation was characterized by low porosity and low permeability. Pore types were mainly <10 nm organic pores, especially in the lower member of the Longmaxi Formation. The size of organic pores increased sharply in the upper member of the Longmaxi Formation. The volumes of methane adsorption were between 1.431 m3/t and 3.719 m3/t, and the total gas contents were between 0.44 m3/t and 5.19 m3/t, both of which gradually decreased from the bottom upwards. Shale with a high TOC content in the carbonaceous siliceous/argillaceous deep shelf is considered to have significant potential for hydrocarbon generation and storage capacity for gas preservation, providing favorable conditions of the source rock and reservoir for shale gas.

scholarly journals Reservoir Characteristics of the Lower Jurassic Lacustrine Shale in the Eastern Sichuan Basin and Its Effect on Gas Properties: An Integrated Approach

Energies ◽  
2020 ◽  
Vol 13 (17) ◽  
pp. 4495
Author(s):  
Jianhua He ◽  
Hucheng Deng ◽  
Ruolong Ma ◽  
Ruyue Wang ◽  
Yuanyuan Wang ◽  
...  
Keyword(s):  
Adsorption Capacity ◽  
Shale Gas ◽  
Lower Jurassic ◽  
Gas Content ◽  
Carbonate Content ◽  
Great Success ◽  
High Porosity ◽  
Reservoir Characteristics ◽  
Laminated Structures ◽  
Gas Properties

The exploration of shale gas in Fuling area achieved great success, but the reservoir characteristics and gas content of the lower Jurassic lacustrine in the northern Fuling areas remain unknown. We conducted organic geochemical analyses, Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction (XRD) analysis, high-pressure mercury intrusion (MIP) and CH4adsorption experimental methods, as well as NMR logging, to study mineral composition, geochemical, pore structure characteristics of organic-rich shales and their effects on the methane adsorption capacity. The Da’anzhai shale member is generally a set of relatively thick (avg. 75 m) and high carbonate-content (avg. 56.89%) lacustrine sediments with moderate total organic carbon (TOC) (avg. 1.12%) and thermal maturation (Vitrinite reflectance (VR): avg. 1.19%). Five types of lithofacies can be classified: marl (ML), calcareous shale (CS), argillaceous shale (AS), muddy siltstone (MS), and silty shale (SS). CS has good reservoir quality with a high porosity (avg. 4.72%). The small pores with the transverse relaxation time of 0.6–1 ms and 1–3 ms comprised the major part of the porosity in the most lithofacies from Nuclear magnetic resonance (NMR) data, while the large pore (>300 ms) accounts for a small porosity proportion in the CS. The pores mainly constitute of mesopores (avg. 23.2 nm). The clay minerals with a large number of interparticle pores in the SEM contributes most to surface area in the shale lithofacies with a moderate TOC. The adsorption potential of shale samples is huge with an average adsorption capacity of 4.38 mL/g and also has high gas content (avg. 1.04 m3/t). The adsorption capacity of shale samples increases when TOC increases and temperature decreases. Considered reservoir properties and gas properties, CS with the laminated structures in the medium-upper section of the Da’anzhai member is the most advantage lithofacies for shale gas exploitation.

Shale Gas-in-Place Calculations Part I: New Pore-Scale Considerations

SPE Journal ◽  
2011 ◽  
Vol 17 (01) ◽  
pp. 219-229 ◽  
Author(s):  
Ray J. Ambrose ◽  
Robert C. Hartman ◽  
Mery Diaz-Campos ◽  
I. Yucel Akkutlu ◽  
Carl H. Sondergeld
Keyword(s):  
Shale Gas ◽  
Organic Material ◽  
Storage Capacity ◽  
Pore Space ◽  
Ion Beam ◽  
Gas Storage ◽  
Organic Content ◽  
Free Gas ◽  
Adsorbed Phase ◽  
Small Pore

Summary Using focused-ion-beam (FIB)/scanning-electron-microscope (SEM) imaging technology, a series of 2D and 3D submicroscale investigations revealed a finely dispersed porous organic (kerogen) material embedded within an inorganic matrix. The organic material has pores and capillaries having characteristic lengths typically less than 100 nm. A significant portion of total gas in place appears to be associated with interconnected large nanopores within the organic material. Thermodynamics (phase behavior) of fluids in these pores is quite different; gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a different density profile. This raises serious questions related to gas-in-place calculations: Under reservoir conditions, what fraction of the pore volume of the organic material can be considered available as free gas, and what fraction is taken up by the adsorbed phase? How accurately is the shale-gas storage capacity estimated using the conventional volumetric methods? And finally, do average densities exist for the free and the adsorbed phases? We combine the Langmuir adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the pore space taken up by the sorbed phase. The method yields a total-gas-in-place prediction. Molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature predict density profiles across the pores and show that (a) the adsorbed methane forms a 0.38-nm monolayer phase and (b) the adsorbed-phase density is 1.8–2.5 times larger than that of bulk methane. These findings could be a more important consideration with larger hydrocarbons and suggest that a significant adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, calculations show a 10–25% decrease in total gas-storage capacity compared with that using the conventional approach. The role of sorbed gas is more important than previously thought. The new methodology is recommended for estimating shale gas in place.

The Gas Content Characteristics of Nanopores Developed in a Normal Pressure Shale Gas Reservoir in Southeast Chongqing, Sichuan Basin, China

2021 ◽  
Vol 21 (1) ◽  
pp. 698-706
Author(s):  
Fangwen Chen ◽  
Qiang Zheng ◽  
Hongqin Zhao ◽  
Xue Ding ◽  
Yiwen Ju ◽  
...  
Keyword(s):  
Organic Carbon ◽  
Shale Gas ◽  
Normal Pressure ◽  
Gas Content ◽  
Organic Carbon Content ◽  
Gas Reservoir ◽  
Free Gas ◽  
Shale Gas Reservoir ◽  
Adsorbed Gas ◽  
Longmaxi Shale

To evaluate the gas content characteristics of nanopores developed in a normal pressure shale gas reservoir, the Py1 well in southeast Chongqing was selected as a case study. A series of experiments was performed to analyze the total organic carbon content, porosity and gas content using core material samples of the Longmaxi Shale from the Py1 well. The results show that the adsorbed gas and free gas content in the nanopores developed in the Py1 well in the normal pressure shale gas reservoir range from 0.46–2.24 m3/t and 0.27–0.83 m3/t, with average values of 1.38 m3/t and 0.50 m3/t, respectively. The adsorbed gas is dominant in the shale gas reservoir, accounting for 53.05–88.23% of the total gas with an average value of 71.43%. The Gas Research Institute (GRI) porosity and adsorbed gas content increase with increasing total organic carbon content. The adsorbed gas and free gas contents both increase with increasing porosity value, and the rate of increase in the adsorbed gas content with porosity is larger than that of free gas. Compared with the other five shale reservoirs in America, the Lower Silurian Longmaxi Shale in the Py1 well developed nanopores but without overpressure, which is not favorable for shale gas enrichment.

The Measurement of Shale Gas Content

2013 ◽  
Vol 288 ◽  
pp. 333-337 ◽  
Author(s):  
Ya Li Jiang ◽  
Hua Qing Xue ◽  
Hong Yan Wang ◽  
Hong Lin Liu ◽  
Gang Yan
Keyword(s):  
Shale Gas ◽  
Sichuan Basin ◽  
Initial Rate ◽  
Direct Method ◽  
Test Procedure ◽  
Mathematic Model ◽  
Gas Content ◽  
Average Value ◽  
Exploration And Production ◽  
Lost Time

The gas content is critical parameter in the shale gas exploration and production. The direct method was used to determine the shale gas content and the apparatus were made by ourselves. It were described the gas content test procedure, mathematic model and data processing in the paper. The adsorb gas and residue gas can be directly obtain from test, and the lost gas was estimated by the initial rate of adsorb gas. The shale gas contents from Sichuan basin are from 1.15 to 1.84 m3/ton, the average value is 1.64 m3/ton. Lost gas is the major gas in the shale and increasing with the lost time. Consequently, the shale should be sealed in the canister as soon as possible to decrease the lost time during the test. It also can enhance the accuracy of gas content. There are a great member of nano-pore and fracture in the organic matter, so that more TOC of shale are more gas content.

Two effective methods for calculating water saturations in shale-gas reservoirs

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. D187-D197 ◽  
Author(s):  
Jingling Xu ◽  
Lei Xu ◽  
Yuxing Qin
Keyword(s):  
Shale Gas ◽  
Water Saturation ◽  
Critical Issue ◽  
Petroleum Exploration ◽  
Gas Content ◽  
Gas Reservoirs ◽  
Gas Saturation ◽  
Shale Gas Reservoirs ◽  
Shale Reservoirs ◽  
Southeastern Sichuan Basin

Water saturation is one of the most important parameters in petroleum exploration and development. However, its calculation has been limited by the insufficient logging data required by a new technique that further influences the calculation of the free gas content. The accuracy of water saturation estimates is also a critical issue because it controls whether or not we can obtain an accurate gas saturation estimate. Organic matter plays an important role in shale-gas reservoirs, and the total organic carbon (TOC) indirectly controls the gas content and gas saturation. Hence, water saturation is influenced by inorganic and organic components. After analyzing the relationship among TOC, core water saturation, and conventional gas saturation, considering the influence of TOC on gas saturation in organic-rich shale reservoirs, we developed two new methods to improve the accuracy of water saturation estimates: the revised water saturation-TOC method and the water saturation separation method, in which Archie water saturation, modified total shale water saturation, and TOC are integrated. According to case studies of Longmaxi-Wufeng shale, southeastern Sichuan Basin, China, the water saturation results from these two methods in shale reservoirs with different lithologies are consistent with those from core analysis. We concluded that these two methods can be evaluated quickly and they effectively evaluate the water saturation of shale reservoirs.

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