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.

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.

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.