Shale Matrix Petrophysical Evolution due to Spontaneous Water Imbibition.

Shale matrix alteration resulting from fracturing water-rock interactions has become a major concern. It significantly affects economic production from shale gas formation. Previous studies mostly failed to investigate the thickness of the water intrusion zone and quantified its effects on shale geophysical alteration. As a result, we present a one-dimensional countercurrent water imbibition model in which capillary pressure and chemical osmosis stress are included. This model is used to predict water front movement with respect to soaking durations. Based on the simulation results and theory derivations, the matrix porosity-permeability and mechanical alteration models are set up to reveal shale geophysical variables change due to shale-water interactions. Our results show that during the water imbibition process, capillary pressure plays a more crucial role than osmosis pressure. Furthermore, both core-scaled porosity and permeability are negatively associated with water saturation, the extent of which depends on different driving forces and penetration depth. Finally, water soaking is quantitatively demonstrated to induce an increase in compressive strength and stress sensitivity but a reduction in the elastic modulus. These findings will provide efficient insights into driving mechanisms involved in the water-rock interactions. The study is useful to be incorporated into production models for predicting hydrocarbon production from shale reservoirs.

Experimental and numerical study on gas production decline trend under ultralong-production-cycle from shale gas wells.

It is of engineering interest to explore recovered shale gas composition and its effects on total gas production trend over a long-term extraction period. However, there are previous experimental studies mostly focused on short term development for small scaled cores, which is less convincing to mimic reservoir-scaled shale production process. In addition, the previous production models mostly failed to account for comprehensive gas nonlinear effects. As a result, in this paper, to illustrate the full-life-cycle production decline phenomenon for shale gas reservoir, dynamic physical simulation was performed for more than 3433 days to simulate shale gas transport out of the formations over a relatively long production period. Moreover, a five-region seepage mathematical model was then developed and was subsequently validated by the experimental results and shale well production data. Our findings show that for physical simulation, both the pressure and production declined steadily at an annual rate of less than 5%, and 67% of the total gas in the core was recovered. These test data supported earlier finding that shale gas is of low flow ability and slow pressure decline in the shale matrices. The production model indicated that free gas accounts for the majority of recovered shale gas at the initial stage. Based on a shale gas well example, free gas extraction makes up 90% of produced total gas. The adsorbed gas constitutes a primary gas source during the later stage. Adsorbed gas contributes more than 50% of the gas produced in the seventh year. The 20-year-cumulative adsorbed gas makes up 21% of the EUR for a single shale gas well. The results of this study can provide a reference for optimizing production systems and adjusting development techniques for shale gas wells throughout the combinations of mathematical modeling and experimental approaches.

Multiple Gas Seepage Mechanisms and Production Development Research for Shale Gas Reservoirs from Experimental Techniques and Theoretical Models.

Shale gas seepage theory provides a scientific basis for dynamically analyzing the physical gas flow processes involved in shale gas extraction and for estimating shale gas production. Conventional experimental techniques and theoretical methods applied in seepage research are unable to accurately illustrate shale gas mass transfer processes at the micro- and nanoscale. In view of these scientific issues, the knowledge of seepage mechanisms and production development design was improved from the perspective of experimental techniques and theoretical models in the paper. First, multiple techniques (e.g., focused ion beam scanning electron microscopy and a combination of mercury intrusion porosimetry and adsorption measurement techniques) were integrated to characterize the micro- and nanopore distribution in shales. Then, molecular dynamics simulations were carried out to analyze the microscale distribution of gas molecules in nanopores. In addition, an upscaled gas flow model for the shale matrix was developed based on molecular dynamics simulations. Finally, the coupled flow and productivity models were set up according to a long-term production physical simulation to identify the production patterns for adsorbed and free gas. The research results show that micropores (diameter: <2 nm) and mesopores (diameter: 2-50 nm) account for more than 70% of all the pores in shales and that they are the primary space hosting adsorbed gas. Molecular simulations reveal that microscopic adsorption layers in organic matter nanopores can be as thick as 0.7 nm and that desorption and diffusion are the main mechanisms behind the migration of gas molecules. An apparent permeability model that comprehensively accounts for adsorption, diffusion, and seepage was developed to address the deficiency of Darcy's law in characterizing gas flowability in shale reservoirs. The productivity model results for a certain gas well show that the production in the first three years accounts for more than 50% of its estimated ultimate recovery and that adsorbed gas contributes more to the annual production than free gas in the eighth year. These research results provide theoretical and technical support for improving the theoretical understanding of shale gas seepage and optimizing shale gas extraction techniques in China.

Modeling a Multi-Parameter Interaction of Geophysical Controls for Production Optimization in Gas Shale Systems.

Well bottomhole pressure optimization issue has been a significant concern for efficiently developing unconventional systems due to strong stress sensitivity. Therefore, it is of practical interest to clarify influence mechanisms involved in stress sensitivity for gas shale, which is further included in the production model to determine main controlling factors for bottomhole pressure strategy optimization for long term hydrocarbon extraction. Currently, many production models were limited in exploring stress sensitivity mechanisms but adopted common empirical equations regarding net pore stress instead. In addition, geophysical control analysis for unconventional systems optimization was mostly conducted using local sensitivity qualitative analysis, which should be validated to be reliable and applicable to fields using multi-parameter interaction influence. As a result, in this paper, an efficient workflow to rationally optimize gas well production system was provided by combining the production model, orthogonal design approach, and response surface method. To be specific, the compound flow model for shale gas reservoirs, incorporating multiple stress sensitivity mechanisms, was proposed to function as a theoretical basis for production optimization simulation. Last but not least, local sensitivity analysis was conducted to qualitatively analyze the impact of influencing factors on 20 year-production of gas wells under different bottomhole production methods. The simulation results showed that the managed pressure drawdown scheme can be adopted for reservoirs with high reservoir pressure and tight matrix properties, while the high-pressure drawdown scheme is suitable for reservoir with better fracturing effect and high external water content. Finally, based on the proposed gas flow model and orthogonal design experiments, response surface design and single factor analysis as well, an optimization mathematical model for shale gas multi-parameter interaction was established, which intuitively quantified the effects of multi-geophysical controls on EUR increase in different production durations, including matrix properties, fracture properties, and production system indicator parameters. These findings provide a more reliable reference for production system optimization based on a series of mathematical approaches to improve overall long-term recovery from shale gas reservoirs.

Bottom-hole pressure drawdown management of fractured horizontal wells in shale gas reservoirs using a semi-analytical model.

Due to strong stress sensitivity resulted from unconventional tight formationsit is of practical interest to formulate a reasonable pressure drawdown plan to improve gas extraction recovery. The impact of water-shale interactions on the reservoir permeability was previously ignored in the managed pressure drawdown optimization. The controlled-pressure production dynamic analysis was mostly conducted using numerical simulation, lack of rigorous theoretical support. Hence in this paper, a theoretical production prediction model was proposed and verified with HIS RTA 2015by incorporating multiple pressure drawdown mechanisms and various non-linear gas flow process. The on-site production effects dominated by two different pressure drop methods was further compared, indicating that compared to depressurization production, the production reversion can occur in the controlled pressure production process and the EUR of single well can be increased by about 30% under the control of managed pressure drawdown approach. Finally, the pressure drawdown optimization strategy was carried out on the field test from the both production effect and economic benefits, which demonstrated that the best economic solution can generally be obtained in the early stage of production. The research results can be closely linked to the on-site production practice of shale gas wells, providing insights into designing optimized production strategy scheme.

Pore Structure Characteristics and Their Controlling Factors of Deep Shale: A Case Study of the Lower Silurian Longmaxi Formation in the Luzhou Area, Southern Sichuan Basin.

Recently, deep shale reservoirs are emerging as time requires and commence occupying a significant position in the further development of shale gas. However, the understanding of pore characteristics in deep shale remains poor, prohibiting accurate estimation of the hydrocarbon content and insights into fluid mobility. This study focuses on the Longmaxi Formation from the Luzhou (LZ) region, southern Sichuan. Scanning electron microscopy (SEM), low-temperature N2/CO2 adsorption, X-ray diffraction, and geochemical analysis were performed to investigate the micro-nanopore size distribution, main controlling factors, and unique pore features distinct from other regions. Results showed that the pores can be classified into four categories, organic matter (OM) pores, intergranular pores, intragranular pores, and microfractures, according to SEM images. The total pore volume is overwhelmingly dominated by mesopores and contributed by pores in the range of 0.5-0.6, 2-4, and 10-30 nm. The specific surface area is primarily contributed by micropores and mesopores in the range of 0.5-0.7 and 2-4 nm. By analyzing the influencing factors extensively, it is concluded that the buried depth, geochemical factors, and mineral composition can impact the pore structure in the overmature deep shales. Specifically, the total organic carbon content plays a more effective and positive role in the development of micropores, mesopores, total pores, and the porosity when compared with vitreous reflectance (Ro). The micropores are inferred to be OM-related. On the contrary, clay mineral is detrimental to the development of micropores and mesopores and the petrophysical properties (porosity and permeability), which may be attributed to the occurrence of chlorite and kaolinite instead of illite. The plagioclase conforms to the same law as clay due to their coexistence. Quartz, carbonate minerals, and pyrite can barely contribute to the pores. Eventually, the compared results suggest that the Longmaxi Formation of the LZ region are qualified with a superior pore size distribution, complicated structure, and diverse morphology, implying a potential to generate and store hydrocarbons. Overall, this study improves the understanding of complex pore structures in deep shale and provides significant insights into the development and exploration of unconventional resources in the future.

Pressure Drawdown Management Strategies for Multifractured Horizontal Wells in Shale Gas Reservoirs: A Review.

The flow capacity of shale gas reservoirs is easily impaired during the depletion process due to strong stress sensitivity. Thereby, an adequate production system, namely, the managed pressure drop method, has been widely introduced to the industrial practice application by decelerating the wellbore pressure drop rate and ultimately improving the long-term production process. This work presents a review of the pressure drawdown management mechanisms for shale gas formations. However, clarifying the water-shale interaction physical chemistry process and developing a mathematical model that accurately describes the water-shale interaction mechanism remain a challenge. Moreover, different classifications of the managed production simulation research approaches are discussed in detail. Each approach has its own merits and demerits. Among them, numerical simulations are commonly seen in cognizance of characterizing the managed pressure drawdown production period but are found to be relatively time-consuming and also computationally expensive. An optimized theoretical model is therefore essential because it can lead to a precise estimation of the ultimate long-term production and capture instantaneously the actual shale gas reservoir depletion phenomenon with various production systems compared to other available methods. The key influence of managed pressured production for single wells in shale reservoirs is elaborated as well. As observed from the current review, an accurate description of the pressure drop management mechanism is crucial for the theoretical model of the pressure control production process for shale gas wells. The influence of water-rock interaction on the managed pressure drawdown mechanism cannot be ignored. There have thus been works to improve and enhance it for use in theoretical models for shale formations. On the other hand, the advancement of theoretical models presents an opportunity for better representation of the managed pressure drop production process.