Increasing Shale Gas Recovery through Thermal Stimulation: Analysis and an Experimental Study

Abstract

The Silurian Longmaxi shale gas play in the Jiaoshiba (JSB) structure in the southeast margin of the Sichuan Basin in China is studied to discuss the key factors that control the adsorption/desorption behavior of natural gas in shale formations. The rationale for this study is that understanding these factors can be helpful in shale gas stimulation designs that enhance recovery by combining hydraulic fracturing with thermally induced desorption of adsorbed shale gas.The Jiaoshiba structure is a faulted anticline which experienced multiphase tectonic movement. The Longmaxi Formation has high thermal evolution degree with Ro more than 2.2%, and has a 35-45 meters thick high-quality shale (TOC Ͼ 2%) in its lower part. The reservoir is overpressure with a pressure coefficient of 1.55, and shale gas production and pressure are stable. Experimental measurements have indicated that more than 65% of the total gas storage in the Jiaoshiba shales exists as an adsorbed phase. Modeling the adsorbed phase can impact the selection of stimulation techniques as well as production forecasts. Adsorption generally cannot be determined accurately from history matching production data alone. The laboratory testing of actual shale samples from reservoir cores is important for characterizing shale gas adsorption behavior.Previous laboratory studies have reported data from measurements at single temperatures, and the measured data have been represented by Langmuir isotherms. However, the effect of temperature on adsorption has not been explored. In this work, a series of experiments were conducted to measure adsorption curves for shale samples at various temperatures and depths from the Jiaoshiba shales. We investigated the representation of adsorption behavior as a function of both temperature and pressure.The pressure-temperature dependent gas adsorption behavior is described by Bi-Langmuir model by fitting the unknown adsorption characteristic parameters against laboratory experiment data at low temperature, the gas adsorption behavior at higher temperature can be predicted by extrapolation from the model. The predicted gas adsorption capacity agree well with our experiment data, which demonstrate this model's capability to predict gas adsorption capacity at reservoir temperature based on data measured at laboratory conditions. The pressure and temperature sensitive gas adsorption behavior is incorporated into an unconventional reservoir simulator, to investigate how thermal stimulation can impact shale gas production and ultimate recovery from hydraulic fractured shale formations. The results indicates that thermal stimulation has the potential to enhance shale gas recovery significantly by altering shale gas adsorption/desorption behavior through the elevation of formation temperature.

What Factors Control Shale-Gas Production and Production-Decline Trend in Fractured Systems: A Comprehensive Analysis and Investigation

“…For organically rich shales, the ultimately recoverable amount of gas is largely a function of the adsorbed gas that can be released (desorbed). Because most adsorbed gas can only be released at low reservoir pressure, due to the extremely low permeability of shale matrix, even with hydraulic fracturing, there is still significant amount of residual absorption gas that cannot be produced, unless additional stimulation methods are used, such as thermal stimulation (Wang et al 2014;Wang et al 2015a;Yue et al 2015). Understanding the effects that initial adsorption, and moreover, desorption has on gas production and decline trend will increase the effectiveness of reservoir management and economic evaluations.…”

A Numerical Study of Thermal-Hydraulic-Mechanical Simulation With Application of Thermal Recovery in Fractured Shale-Gas Reservoirs

“…The inclusion of temperature effects add more complexity in reservoir modeling and simulation, because the changes in formation temperature not only alter gas adsorption capacity, vary real gas properties, induce thermal stress, but also impact matrix permeability and fracture conductivity in a fully coupled manner, which in turn, affect in-situ flow capacity and ultimate recovery. Fig.3 shows laboratory measurement and theoretical model prediction of gas adsorption capacity at different temperatures from a shale sample (Yue et al, 2015). By examining the adsorption curves, we can deduce that the reservoir pressure must be sufficiently low to liberate the adsorbed gas and the ultimately recoverable amount of gas is largely a function of the adsorbed gas that can be released (desorbed).…”

“…( A.19) can be determined from a Langmuir isotherm curve at provided temperature condition by non-linear regression. Thus, the temperature effects can be included to describe shale gas adsorption capacity as a function of both pressure and temperature (as shown in Fig.6), with available Langmuir volume and Langmuir pressure values as input parameters (Wang et al, 2014), or directly fitting and validated against experiment data within possible temperature ranges (Yue et al, 2015).…”

“…They concluded that if kerogen present in sufficient quantities, methane combustion can generate enough heat to enhance the permeability. Yue et al (2015) conducted laboratory experiment on shale samples, by measuring shale gas adsorption capacity with different temperatures, their work indicates that large amount of adsorption gas can be expelled by elevating temperature and the sensitivity of gas adsorption capacity to temperature depends on rock mineralogy properties.…”

Three-dimensional numerical simulation of enhancing shale gas desorption by electrical heating with horizontal wells

“…In recent years, many researchers (Lin et al, 2015;Zhu et al, 2016;Wang et al, 56 2014; Wang et al, 2015) have investigated shale gas production enhancement by increasing 57 formation temperature. Lin et al (2015) assessed the effect of temperature on shale gas adsorption 58 and numerically simulated how thermal stimulation affected shale gas production. Their results 59…”