Summary Gas content is a key parameter for the determination of the gas resources in unconventional reservoirs. In this study, we propose a novel method to evaluate the gas content of shale through a new perspective: fractionation of carbon isotopes of methane. A detailed understanding of the mechanism of fractionation of the isotopes is obtained for the first time and the Knudsen-diffusivity difference is identified as the dominant factor for fractionation according to the different molecular weights of the isotopes. Then, the simulated results of BG-CDAM and the measured data from an isotope-logging test are combined to determine the unknown parameters for gas-content calculation. The proposed method for organic shale is valid and useful to obtain the quantitative component proportion in gas content, such as lost gas, degassing gas and residual gas, or free gas and adsorption gas. Thus, this method could provide a promising means for the identification of sweet spots in shale-gas reservoirs. Moreover, the method might have the potential to economically and rapidly evaluate the remaining resources in producing wells in future applications. Introduction Shale gas is the natural gas retained and accumulated in source shale and it is characterized as self-generating and self-storing. It is mainly stored in shale reservoirs in the forms of free gas and adsorption gas. Adsorption gas, with proportion ranges from 20 to 85% (average of 50%) of the total gas in shale (Curtis 2002; Zhang et al. 2004), has a close relationship with the gas content (Meng et al. 2016). Although there might be a wide range of gas content in organic-shale formations, only when gas content reaches a certain level (for example, the gas-content limit in the US is 0.5 to 1.0 m 3 /t) can it be considered economical to develop (Zhang et al. 2012). The exploration and development of shale gas have attracted extensive attention around the world.

Much attention has been attracted by the successful development of shale gas reservoir in recent decades. Correspondingly, research aspects of shale gas reservoirs become more and more heat among the academic community, especially in the fields of nanoscale gas transport mechanisms as well as the storage modes. Fascinated by the craft interactions exerted by organic or inorganic shale surface, drastic discrepancy takes place in terms of the gas behavior inside the nanoscale dimension and that in conventional dimension. It is crucial to figure out the exact influence on shale gas recovery and overall production efficiency due to the above large difference. Notably, this paper is designed to comprehensively explore the methane storage behavior in shale nanopores, expecting to provide the direct relationship between adsorption gas and free gas content under various environmental conditions. Also, a novel and simple prediction method with regard to ultimate gas recovery is proposed, which is connected to the pore size distribution and formation pressure. First of all, the gas storage modes in a single nanopore with defined pore size are analyzed seriously. As a result, the evaluation model is constructed for adsorption gas and free gas content in a single nanopore. After that, an upscaling method is applied to extend the adaptiability of the model from single nanopore to nanoporous modia. Finally, sensitivity factor analysis work is performed and a recovery prediction methodology is developed. Results suggest that the adsorption gas content will be a larger contribution to total gas content when it comes to small pore radius and low formation pressure. In contrast, free gas content will increase with the increasing pressure and pore size. More importantly, pore size distribution characteristic has a key impact on gas storage modes and ultimate gas recovery. The high proportion of small nanopores plays a detrimental role on gas recovery, resulting in large content of adsorption gas at low pressure, which will not be produced and remain in shale gas reservoirs.

Abstract

Shale reservoir exploration technology has attracted increasing attention, and total porosity is a parameter that characterizes the shale storage. Due to the complexity of mineral components and the large variety of pore types, the evaluation accuracy of total porosity of shale reservoirs is not satisfactory, at present. To address this problem, this paper proposes an evaluation method for shale reservoir total porosity based on a shale petrophysical model. We first established the petrophysical model for the calculation of total porosity and then eliminated the effect of gas saturation in the petrophysical model by combining density and neutron-porosity logging. After that, evaluations of matrix density, matrix neutron porosity, and organic matter were conducted using a combined method of elemental logging and conventional logging. Finally, the total porosity of the shale reservoir was calculated. The calculation results showed that by using the elemental logging method and based on actual conditions in the research area, the shale mineral composition could be obtained, and an accurate evaluation of matrix neutron porosity and matrix density could be realized. The total organic carbon (TOC) and organic matter (OM) in the shale reservoir can be accurately calculated according to conventional logging data. The evaluation accuracy of total porosity by this method was high, wherein the predicted relative error was only 0.4. Moreover, based on theoretical deduction, it is known that the proposed method has high applicability for shale reservoirs. If the inversion effect of matrix minerals can be guaranteed, an accurate calculation of shale total porosity can be obtained. In summary, the proposed method can accurately calculate the total porosity of shale reservoirs, which provides a reference for the exploration and exploitation of shale reservoirs.

Summary

Activity in the Ordos Basin, China, has mostly occurred in the low-permeability, clay-rich Chang 7 sandstone, and has used multifractured horizontal wells as the preferred completion technique. To improve further the production potential and to increase operational efficiency, a dual-well pad site was engineered to try a pad-drilling approach and to evaluate different completion techniques, use integrated work flows, and accelerate the development cycle.

The pilot project involved two pads with two horizontal wells each, with the intention to compare the local multistage stimulation practice of using a tubing-conveyed completion method to a wireline-conveyed plug-and-perforation technique. The current tubing-conveyed completion practice affects the completion efficiency of the well from the standpoints of surface efficiency, engineering work flow, post-fracturing performance, and subsequent commercial performance. The wells completed with the plug-and-perforation technique were completed in a shorter period of time; simultaneous operations enabled flowback water from the first well to be recycled and reused on pumping operations on the second well, further improving the project performance, and first-year cumulative production was 20% higher compared with surrounding offsets.

Three vertical wells were placed between the parallel horizontal wells to enable real-time fracturing monitoring and to improve subsurface understanding. To have a more-precise microseismic mapping result, the closest vertical well was selected as the monitoring well.

The study demonstrates the importance of an integrated approach that accounts for well design, engineering work flow, technology used during the execution, and subsequent evaluation while improving overall productivity. Both the efficiency and the production result were breakthroughs in this area.

Less than half of the injected fracturing fluid in gas shale is often recovered and in many cases the flowback efficiency is <20%, which relates to potential productivity hindrance. Some have suggested that the water migration in the neighborhood of fractures induced by spontaneous imbibition contributes to auto-removal mechanism of water damage. However, water imbibition into fractured shale reservoirs is a physic-chemical and multiscale flow process, which is significantly different from conventional reservoirs. Therefore, we systematically characterize the samples by measuring the porosity, permeability, wetting angle and mineral composition. Comparative imbibition experiments are performed on 18 binary core plugs from typical formations of China's basin (i.e., Ordos Basin, Songliao Basin and Sichuan Basin). The preliminary result shows that Handy imbibition model has an evident deviation in predicting the shale imbibition experiment result, which is significantly overestimated. This disagreement can be explained by strong fluid-wall interactions in micron-nano pores. In addition to the widely believed capillary driving forces and viscous forces, the overall resistance of fluid-wall interactions have an important impact on water migration, which could reduce the imbibition rate in gas shale. A critical aperture Dc of about 36~100nm exits, which can be used to address the effects of fluid-wall interactions. The matrix blocks with average pore size of > Dc tend to produce minor resistance effects of fluid-wall interaction on imbibition rate. Handy model can provide a good match with experimental imbibition in micro-fractures or macropores; in the contrary, the matrix blocks with average pore size of <Dc tend to exert significant resistance effects of fluid-wall interaction on imbibition rate. Handy model reproduce the global trend of variation, which has been inadequate. The results of our study are more valuable for the comprehension of auto-removal water damage process and optimization of flowback time after fracturing operations in gas shale.

Summary

As the underbalanced-drilling (UBD) technique develops, the benefits for eliminating formation damage and improving productivity have been well received by Chinese national oil companies. Potential candidates for UBD reservoirs are tight sandstone and volcanic rock, as well as other low-permeability hard rocks. Not all candidates are ultimately suitable. Experience in China suggests that inappropriate application of underbalanced reservoir drilling may have an adverse effect on protecting reservoirs, which in turn increases drilling risks. To achieve successful application of the technique, it is essential first to fully evaluate the suitability of the reservoir for UBD. Furthermore, it has been observed that there is a lack of research when it comes to evaluation of reservoir suitability with respect to UBD opportunities in China. Most current basin studies in China focus on geographic distributions and reservoir lithology characterizations rather than geomechanical properties.

This paper addresses these gaps by presenting the result of a China UBD basins study. We have applied our reservoir-screening process to reservoirs in 382 oil and gas fields and 17 onshore basins of China to determine whether or not these reservoirs are practical for UBD. Candidacy is determined by evaluating a number of formation-damage mechanisms and related operational risks within the reservoir-screening process. The research then identifies formation-damage mechanisms of the UBD reservoir candidates and also presents a ranking from high-potential to low-potential reservoirs for the suitability of UBD, and establishes the highest production potential by application of the UBD technique.

Also, the objective of the research is to evaluate and rank the suitability of reservoirs for exploitation by UBD compared with conventional drilling and completion processes. Proper identification of UBD opportunities will minimize drilling risks for Chinese national oil companies.

As the Underbalanced Drilling (UBD) technique develops, the benefits for eliminating formation damage and improving productivity have been well received by China National Oil Companies. Potential candidates for UBD reservoirs are tight sandstone, volcanic rock, as well as other low permeability hard rocks, but not all candidates are ultimately suitable. Experience in China suggests that inappropriate application of underbalanced reservoir drilling may have an adverse effect on protecting reservoirs, which in turn increases drilling risks. To achieve successful application of the technique, it is essential to first fully evaluate the suitability of the reservoir for underbalanced drilling. Furthermore, it has been observed that there is a lack of research when it comes to evaluate reservoir suitability with respect to UBD opportunities in China. Most current basin studies in China focus on geographic distributions and reservoir lithology characterizations rather than geomechanical properties.

This paper addresses these gaps by presenting the result of a China UBD basins study. We have applied our Reservoir Screening Tool software (RST) to reservoirs in 382 oil and gas fields and 17 onshore basins of China, to determine whether or not these reservoirs are practical for Underbalanced Drilling. Candidacy is determined by evaluating a number of formation damage mechanisms and related operational risks within the RST process. The research then results in the identifications of formation damage mechanisms of the UBD reservoir candidates, and also presents a rank from high potential to low potential reservoirs for the suitability of UB Drilling, and establishes the highest production potential applied by UBD technique.

Also, the objective of the research is to evaluate and rank the suitability of reservoirs for exploitation by UBD compared with conventional drilling and completion processes. Proper identification of UBD opportunities will minimize drilling risks for China national oil companies.

Phase 3: sustained development stage of exploration and of both up-and downstream sections. RPR is a key factor in production: in this phase, the production rate and RPR would the strategy of natural gas development. It has been realized remain relatively steady, reflecting a balance between that the level of RPR is related with the harmonious exploration and production. For the case of America (since development of the natural gas industry: For the upstream of 1974), the production rate sustained between 530-630 bcm/a, gas industry, RPR is not only a balance between exploration and RPR remained 8.3 to 11.6. RPR is often taken Gas development in China.