NMR Analysis Method of Gas Flow Pattern in the Process of Shale Gas Depletion Development

Shale gas reservoirs have pores of various sizes, in which gas flows in different patterns. The coexistence of multiple gas flow patterns is common. In order to quantitatively characterize the flow pattern in the process of shale gas depletion development, a physical simulation experiment of shale gas depletion development was designed, and a high-pressure on-line NMR analysis method of gas flow pattern in this process was proposed. The signal amplitudes of methane in pores of various sizes at different pressure levels were calculated according to the conversion relationship between the NMR T 2 relaxation time and pore radius, and then, the flow patterns of methane in pores of various sizes under different pore pressure conditions were analyzed as per the flow pattern determination criteria. It is found that there are three flow patterns in the process of shale gas depletion development, i.e., continuous medium flow, slip flow, and transitional flow, which account for 73.5%, 25.8%, and 0.7% of total gas flow, respectively. When the pore pressure is high, the continuous medium flow is dominant. With the gas production in shale reservoir, the pore pressure decreases, the Knudsen number increases, and the pore size range of slip flow zone and transitional flow zone expands. When the reservoir pressure is higher than the critical desorption pressure, the adsorbed gas is not desorbed intensively, and the produced gas is mainly free gas. When the reservoir pressure is lower than the critical desorption pressure, the adsorbed gas is gradually desorbed, and the proportion of desorbed gas in the produced gas gradually increases.

Effect of reservoir pressure and total organic content on adsorbed gas production in shale reservoirs: a numerical modelling study

Adsorbed gas plays a key role in organic-rich shale gas production due to its potential to contribute up to 60% of the total gas production. The amount of gas potentially adsorbed on organic-rich shale is controlled by thermal maturity, total organic content (TOC), and reservoir pressure. Whilst those factors have been extensively studied in literature, the factors governing desorption behaviour have not been elucidated, presenting a substantial impediment in managing and predicting the performance of shale gas reservoirs. Therefore, in this paper, a simulation study was carried out to examine the effect of reservoir depth and TOC on the contribution of adsorbed gas to shale gas production. The multi-porosity and multi-permeability model, hydraulic fractures, and local grid refinements were incorporated in the numerical modelling to simulate gas storage and transient behaviour within matrix and fracture regions. The model was then calibrated using core data analysis from literature for Barnett shales. Sensitivity analysis was performed on a range of reservoir depth and TOC to quantify and investigate the contribution of adsorbed gas to total gas production. The simulation results show the contribution of adsorbed gas to shale gas production decreases with increasing reservoir depth regardless of TOC. In contrast, the contribution increases with increasing TOC. However, the impact of TOC on the contribution of adsorbed gas production becomes minor with increasing reservoir depth (pressure). Moreover, the results suggest that adsorbed gas may contribute up to 26% of the total gas production in shallow (below 4,000 feet) shale plays. These study findings highlight the importance of Langmuir isothermal behaviour in shallow shale plays and enhance understanding of desorption behaviour in shale reservoirs; they offer significant contributions to reaching the target of net-zero CO2 emissions for energy transitions by exhibiting insights in the application of enhanced shale gas recovery and CO2 sequestration — in particular, the simulation results suggest that CO2 injection into shallow shale reservoirs rich in TOC, would give a much better performance to unlock the adsorbed gas and sequestrate CO2 compared to deep shales.

Low-Permeable Reservoirs as High Potential Assets for EGR

Natural gas fields that are being developed in Ukraine, mainly relate to the high and medium permeability reservoirs, most of which are at the final stage of field life. In this situation one of the main sources of additional gas production is unconventional fields. This paper presents the analysis of challenges concerning development of low-permeable reservoirs and experimental results of conducted research, which provide the opportunity to establish technologies for enhance gas recovery factor. For this purpose, a series of laboratory experiments were carried out on the sand packed models of gas field with different permeability (from 9.7 to 93 mD) using natural gas. The pressure in the experiments varied from 1 to 10 MPa, temperature – 22-60 °C. According to the features of low-permeable gas fields development the research of displacement desorption with carbon dioxide and inert gas stripping by nitrogen was conducted. These studies also revealed the influence of pressure, temperature, reservoir permeability and non-hydrocarbon gases injection rate on the course of adsorption-desorption processes and their impact on the gas recovery factor. According to the experimental results of relative adsorption capacity determination it can be concluded that the carbon dioxide usage as the displacement agent can lead to producing adsorbed gas by more than 30% than by using nitrogen. To remove the adsorbed gas just reservoir pressure lowering is not enough due to the nature of adsorption isotherms. Particularly at pressure decreasing by 8-10 times compared to initial reservoir pressure only about 30-40% of the total amount of initially adsorbed gas is desorbed. And at considerable reservoir pressure reduction the further deposit development is not economically profitable. According to the results it was found that in the case of nitrogen usage the most effective method is full voidage replacement at injection pressure of 0.8 of the initial reservoir pressure, and in case of carbon dioxide usage - full voidage replacement method at pressure of 0.6 of the initial reservoir pressure. Taking into account availability of N2 and CO2, N2injection is recommended for further implementation. The influence of displacement agent injection pressure on gas recovery was experimentally proved. The physical sense of the processes taking place during natural gas desorption stimulation by non-hydrocarbon gases was justified. The effect of temperature, pressure and reservoir permeability on methane adsorption capacity were determined. The mathematical model for estimating adsorbed gas amount depending on the reservoir parameters was developed. Obtained results were summarized and recommendations for practical implementation of elaborated technological solutions were suggested.

Experimental Study on Percolation Rate Characteristics of Gas-Filled Coal Bodies Based on True Triaxial Condition

To research the percolation rate of gas-filled coal based on true triaxial condition, this paper uses the three-phase coupling true triaxial servo test device to carry out the seepage test of coal, and the percolation rate of coal under different conditions of three factors such as gas pressure was measured by Darcy’s law, and the variation of percolation rate of coal was studied based on the comprehensive consideration of thermal elastic swelling deformation, expansion deformation of adsorbed gas, and compression deformation of interstitial pressure. The results are as follows: (1) When the main stress and temperature maintain unchanged, the percolation rate presents the trend which first decreases and then becomes gentle with the gas pressure; when the gas pressure and main stress maintain unchanged, the percolation rate increases with the decrease of temperature; when the pressure and temperature maintain unchanged, the changes of percolation rate present a shape of “V” with the main stress. (2) The strain curve of gas-filled coal decreases at first and then increases; that is, the percolation rate decreases gradually when the strain increases at the compression phase and elastic phase, while the percolation rate increases with the increase of strain at the yield phase and failure phase. (3) In the process of increasing volume stress, the percolation rate decreases gradually in the pore compaction stage, the percolation rate increases gradually from crack propagation to peak failure stage, and then, the percolation rate increases significantly after the peak damage. According to the test results, the percolation rate and volume strain show an inverse proportion.

Desorption and Transport of Temperature-Pressure Effect on Adsorbed Gas in Coal Samples from Zhangxiaolou Mine, China

The development of coal seam fissures and gas migration process caused by mining disturbance has an extremely important influence on gas control and roadway stability. In this study, the desorption, diffusion, and migration tests of adsorbed gas under the coupling effect of temperature and uniaxial compression were conducted on four coal samples from Zhangxiaolou mine, using the temperature and pressure coupling test system of deep coal rocks. The test confirms that the higher the temperature, the faster the desorption and emission of the adsorbed gases in the coal, and the larger the volume of the emitted gases. Meanwhile, it is found that the adsorbed gases in the coal samples of Zhangxiaolou mine are carbon dioxide and methane in the order of content. It is found that during the uniaxial compression process, several large negative values of the pressure of the emitted gas occur during the stable growth stage of the crack. This indicates that the crack expansion makes a new negative pressure space inside the coal sample, and the negative pressure values increase continuously during the unstable growth phase of the crack until the coal sample is destroyed. And after the axial pressure is removed, the escaped gas pressure shows a large positive value due to the rebound of the coal matrix and the continuous desorption of a large amount of adsorbed gas from the new crack location, which has a significant hysteresis with respect to the occurrence of the peak stress. Meanwhile, the SEM images of the coal samples before and after the test are analyzed to confirm the cause of the negative pressure generation.

A Semianalytical Production Prediction Model and Dynamics Performance Analysis for Shale Gas Wells

The shale gas productivity model based on shale gas nonlinear seepage mechanism is an effective way to reasonably predict productivity. The incomplete gas nonlinear effects considered in the current production prediction models can lead to inaccurate production prediction. Based on the conventional five-zone compound flow model, comprehensive gas nonlinearities were considered in the improved compound linear flow model proposed in the paper and a semianalytical solution for productivity was obtained. The reliability of the productivity model was verified by the field data, and then, the 20-year production performance analysis of the gas well was studied. Ultimately, the key influencing factors of the fracture control stage and matrix control stage have been analyzed. Research indicated the following: (1) the EUR predicted by the productivity model is higher than the EUR that the comprehensive nonlinear effects are not considered, which demonstrated that the various nonlinear effects cannot be neglected during the production prediction to ensure the greater calculation accuracy; (2) during the early production stage of shale reservoir, the adsorbed gas is basically not recovered, and the cumulative adsorption contribution rate does not exceed 10%. The final adsorption gas contribution rate is 23.28%, and the annual adsorption rate can exceed 50% in the 20th year, showing that free gas and adsorbed gas are, respectively, important sources of the early stage of production and long-term stable production; (3) the widely ranged three-dimensional fracturing reformation of shale reservoirs and reasonable bottom hole pressure in the later matrix development process should be implemented to increase the effective early production of the reservoir and ensure the earlier gas production process of the matrix development. The findings of this study can help for better ensuring the prediction accuracy of the estimated ultimate recovery and understanding the main influencing factors of the dynamic performance of gas wells so as to provide a theoretical reference for production optimization and development plan formulation of the shale gas reservoirs.

Quantification of Temperature-Dependent Sorption Kinetics in Shale Gas Reservoirs: Experiment and Theory

A critical component of natural gas in organic-rich shales is adsorbed gas within organic matter. Quantification of adsorbed gas is essential for reliable estimates of gas-in-place in shale reservoirs. However, conventional high-pressure adsorption measurements for coal on the volumetric method are prone to error when applied to characterize sorption kinetics in shale-gas systems due to limited adsorption capacity and finer pores of shale matrix. An innovated laboratory apparatus and measurement procedures have been developed for accurate determination of the relatively small amount of adsorbed gas in the Marcellus shale sample. The custom-built volumetric apparatus is a differential unit composed of two identical single-sided units (one blank and one adsorption side) connected with a differential pressure transducer. The scale of the differential pressure transducer is ± 50 psi, a hundred-fold smaller than the absolute pressure transducer measuring to 5000 psi, leading to a significant increase in the accuracy of adsorption measurement. Methane adsorption isotherms on Marcellus shale are measured at 303, 313, 323 and 333 K with pressure up to 3000 psi. A fugacity-based Dubinin-Astakhov (D-A) isotherm is implemented to correct for the non-ideality and predict the temperature-dependence of supercritical gas sorption. The Marcellus shale studied displays generally linear correlations between adsorption capacity and pressure over the range of temperature and pressure investigated, indicating the presence of a solute gas component. It is noted that the condensed phase gas storage exists as the adsorbed gas on shale surface and dissolved gas in kerogen, where the solute gas amount is proportional to the partial pressure of that gas above the solution. To our best understanding, it is the first time to observe the contribution of dissolved gas to total gas storage. With adsorption potential being modeled by a temperature dependence expression, the D-A isotherm can successfully describe supercritical gas sorption for shale at multiple temperatures. Adsorption capacity remarkably decreases with temperature attributed to the isosteric heat of adsorption. Lastly, the wide applicability of the proposed fugacity-based D-A model is also tested for literature adsorption data on Woodford, Barnett, and Devonian shale. Overall, the fugacity-based D-A isotherm provides precise representations of the temperature-dependent gas adsorption on shales investigated in this work. The application of the proposed adsorption model allows predicting adsorption data at multiple temperatures based on the adsorption data collected at a single temperature. This study lays the foundation for accurate evaluation of gas storage in shale.

Experimental Study on the Characteristics of Adsorbed Gas and Gas Production in Shale Formations

Adsorbed gas and free gas both exist in shale reservoirs simultaneously due to the unique nanoscale pore structure, resulting in the complex flow mechanism of gas in the reservoir during the development process. The dynamic performance analysis of shale reservoirs has mostly been conducted by the numerical simulation and theoretical model, while the physical simulation method for relevant research is seen rarely in the literature. Thus, in this paper, an experiment system was designed to simulate the degraded development experiments of shale, coal, and tight sandstone to reveal the output law of gas in different occurrence states of shale reservoirs and clarify the pressure propagation rules of different reservoirs, and then, adsorption gas and free gas production laws were studied by theoretical models. Research indicated the following: (1) The gas occurrence state is the main factor that causes the difference of the pressure drop rate and gas production law of shale, coal, and tight sandstone. During the early stage of the development of shale gas, the free gas is mainly produced; the final contribution of free gas production can reach more than 90%. (2) The static desorption and dynamic experiments confirm that the critical desorption pressure of adsorbed gas is generally between 12 and 15 MPa. When the gas reservoir pressure is lower than the critical desorption pressure in shale and coal formation, desorption occurs. Due to the slow propagation of shale matrix pressure, desorption of adsorbed gas occurs mainly in the low-pressure region close to the fracture surface. (3) The material balance theory of closed gas reservoirs and the one-dimensional flow model of shale gas have subsequently validated the production performance law of adsorbed gas and free gas by the physical simulation. Therefore, in the practical development of shale gas reservoirs, it is recommended to shorten the matrix supply distance, reduce the pressure in the fracture, increase the effective pressure gradient, and enhance the potential utilization of adsorbed gas as soon as possible to increase the ultimate recovery. The findings of this study can help for a better understanding of the shale reservoir utilization law so as to provide a reference for production optimization and development plan formulation of the shale gas reservoirs.