Search

Enhanced Geothermal Systems (EGS), engineered deep rock heat exchangers, are often touted for their massive untapped renewable energy potential. However, numerous technical and financial challenges must be overcome before the technology is widely deployed. To be viable, EGS must engineer a heat sweep by circulating fluid through a large volume of rock while minimizing fast pathways that create thermal short circuits. Here, we propose a new horizontal EGS well design with partially bridging multi-stage hydraulic fractures (Fig. 1b) to improve heat extraction from hot dry rock (HDR). In order to increase fluid circulation through the stimulated reservoir volume (SRV) between fractures, the hydraulic fractures are created in an alternating pattern between injection and production wells, with each stopping short of connecting the second well. To test this design, we developed a thermal-hydro-mechanical (THM) coupling model and investigated heat extraction performance and reservoir stress evolution during operation. Fractures were modelled as opening contact surfaces with system stresses evolving according to thermal, poroelastic, and fracture opening effects. Based on the model, the temperature performance of proposed EGS design model is compared with the commonly used fully bridging EGS design model (Fig. 1a). An investigation of thermal performance showed that the proposed design obtains higher production temperatures and delays thermal breakthrough by several years compared to a fully-bridging fracture design. It also results in a greater degree of secondary stimulation of the SRV as cold fluids are forced further into the rock matrix . These results indicate that the partially-bridging fracture design is a promising candidate for practical EGS implementation.

In coal-bed methane (CBM) field development plan, more attention is paid to production forecasting, well spacing optimization, pressure transient analysis and adsorption/desorption mechanism within coal matrix. Few studies were carried out to investigate the expansion of drainage and desorption area based on the characteristics of pressure propagation in CBM reservoir. Moreover, the production rate and bottom-hole pressure (BHP) are usually variable, while the production system in current analytical models are either at constant production rate or constant BHP. When optimizing the production system of CBM well, the knowledge of expansion principle of drainage and desorption area can help obtain the critical time of interference and its intensity, which are both key factors for efficient development of CBM reservoirs. In this paper, a comprehensive method for drainage and desorption area expansion during coal-bed methane production is proposed, in which the variable rate and BHP in different production stages and saturation distribution are considered. The coal seam is divided into two areas, namely desorption and without-desorption area, and the production life is divided into five stages. The pressure profiles at different production stages are detailed investigated utilizing diffusivity equation which is solved by the continuous succession of steady states. By assuming the desorption area with low water-gas ratio and without-desorption area with high water-gas ratio, the pressure-squared approach is applied in desorption area and pressure approach is employed in without-desorption area. Finally, a model for predicting drainage and desorption area is developed by generating pressure profile and material balance equation. The proposed semi-analytical model is verified by numerical simulation with excellent agreement with the simulation data. Results show that the drainage area expands much faster at early production stage than that at late stage when desorption area starts expanding in the coal-bed reservoir. In addition, the production system of CBM well is found to play a significant role in the expansion characteristics of desorption area. Considering these characteristics of CBM, we shed light on the production system optimization in different production stages and apply the developed production system to a CBM well in Qinshui field, China. In summary, this method only requires BHP, gas and water production, and turns out to be simple, reliable and powerful in application.

Huge amount of works have been done on wellbore modeling, but most of the researchers focused on saturated thermal fluid, with very little efforts on superheated multi-component thermal fluid (SMTF). In this paper, the authors presented a novel model for predicting thermophysical properties of SMTF in concentric dual-tubing wells (CDTW). Firstly, based on real gas state equation, a novel model comprised of mass, momentum and energy balance equation in the integral joint tubing (IJT) and annuli was proposed for CDTW. Secondly, type curves of SMTF flow in CDTW were obtained from the mathematical model mainly by finite difference method and iteration technique. Finally, validation and sensitivity analysis of the model were sequentially conducted. The validation results showed that the predicted results were in agreement with field test results, which proved the correctness of the model. Type curves of SMTF flow in CDTW showed that the injection temperature difference between the IJT and annuli has a strong influence on the profiles of temperature and superheat degree in each tubing. According to the sensitivity analysis of the model, the superheat degree in the IJT decreases with the increase of injection pressure in the IJT, but the superheat degree in annuli does the opposite. The superheat degree in the IJT increases with the increase of injection pressure in annuli, but the superheat degree in annuli does the opposite. Both of the temperature and superheat degree in each tubing decreases with the increase of non-condensing gas content. This paper gives the engineers a novel insight into what is the distribution characteristics of thermophysical properties of SMTF in CDTW, and provides an optimization method of injection parameters for oilfield.

In this paper, a novel model is presented for predicting thermophysical properties of superheated steam (SHS) in offshore superheated steam injection wells (OSSIW). Firstly, a mathematical model comprised of mass, energy and momentum balance equations is proposed for OSSIW. Secondly, the distribution of temperature, pressure and superheat degree along the wellbores are obtained by finite difference method on space and solved by using the iteration technique. Then, model validation and sensitivity analysis are conducted. The results show that (1). The superheat degree increases at first but then turns to decrease with the increase of injection rate. (3). The superheat degree increases with the increase of injection temperature. (4). The superheat degree at well bottom increases at first but then turns to decrease with the increase of injection pressure. (5). The superheat degree in the wellbore has a drop when seawater starts to flow.

Methane adsorption in shale is a gas–liquid–solid interaction rather than a gas–solid interaction by considering the initial water saturation in actual condition. As an important constituent of inorganic matter, clay minerals may affect gas-in-place of shale systems. Generally, Clay minerals are strongly hydrophilic with a water film bound on its surface, significantly reducing gas sorption capacity, which will lead to overestimate gas-in-place (GIP) of shale gas reservoir. In this work, we analyze the interactions between methane, water film and clay, and results reveal that: methane adsorption on clay (dry) is a typical gas–solid interaction; however, methane adsorption on clay bound water film should belong to gas–liquid interaction. Furthermore, a unified model is established to describe gas-water-clay interactions, in which, gas–solid Langmuir equation and gas–liquid Gibbs equation are integrated by water coverage coefficient. Meanwhile, a mathematical model is presented to quantify thickness of water films by considering surface force interactions between liquid film and clay. Our results show that, the water film thickness in shale clay pores mainly depends on relative humidity and pore size. Under a certain humidity condition (such as 0.98), the water saturation distribute in different sized pores mainly as: (i) capillary water in the small pores (

The greenhouse effect has brought about a series of ecological and environmental problems such as wind intensification, species extinction, acid rain, awful weather, sea-level rise, which are mainly caused by CO2 among all greenhouse gases. It is an effective way to alleviate the problem by injecting CO2 into shale reservoir. Such technology is the focus of attention of government and the public, and has been provided with well-established mathematical models and simulation software. While, compared to the mature development of this technology abroad, China is still on emerging state and studies on CO2 storage under shale reservoir was just launched. Given the current situation of domestic studies, this paper mainly probes into the mechanism of CO2 storage under shale reservoir, influencing factors, and provides the mathematical model for enhancing recovery of CO2 storage under shale reservoir based on dual medium hypothesis, in which, are viscous flow, molecular diffusion, coupling effect of Knudsen diffusion mechanism are taken into consideration. And then this paper develops the channeling equation with an eye to the coupling migration mechanism, provides source sink term model for production well and injection well, and gives research on numerical simulation. Finally, this paper discusses feasibility of enhancing recovery of CO2 storage under shale gas reservoir and analyzes the dynamic changes of CO2 storage volume and CH4 production volume during injection of CO2.