An analytical model for shale gas permeability
页岩透气性分析模型
International Journal of Coal Geology, Volume 146, 1 July 2015, Pages 188-197
Abstract: Based on the kinetic theory of gases and using the regularized 13-moment method, the analytical R13 AP model is introduced for predicting gas apparent permeability of nanoporous shale samples. These samples are characterized by ultratight pores and may introduce significant rarefaction effects, especially under the laboratory conditions, which cannot be accounted for in the classical hydrodynamic equations. Due to the significance of the rarefaction effects, measured values of the gas apparent permeability depend on the operating parameters, such as pressure and temperature, and gas type in addition to pore size. The R13 AP model incorporates these parameters and can predict the apparent permeability for Knudsen numbers up to unity. This model is compared with the other models and experimental results. The results of the R13 AP model match the published experimental data of flow in nanochannels. It is shown that the gas molecular weight and temperature have a significant effect on apparent permeability of the nanochannels, and the Tangential Momentum Accommodation Coefficient (TMAC) has a minimal effect for its experimental range (0.8–1). The effect of adsorption on apparent permeability of nanochannels is studied by employing the experimental Langmuir isotherms of different shale samples. It is shown that the apparent permeability does not change linearly with surface coverage and, change of permeability with surface coverage becomes more pronounced as the surface coverage increases. R13 AP model results for apparent permeability of Carbon Dioxide and Nitrogen agree with the experimental measurements performed on a Marcellus shale sample. The absolute permeability values are calculated and compared with the ones estimated by the double slippage model for both gases. Unlike the double slippage model, the R13 AP model honors the values of apparent permeability at high pressure and estimates lower absolute permeability values. For Carbon Dioxide, the value is slightly lower due to the presence of an adsorbed layer.
Experimental investigation on the characteristics of gas diffusion in shale gas reservoir using porosity and permeability of nanopore scale
基于纳米孔尺度多孔性与渗透性的页岩气藏气体扩散特征实验研究
Journal of Petroleum Science and Engineering, Volume 133, September 2015, Pages 226-237
Abstract: The aim of this study is to investigate the diffusion characteristics of nanoscale gas flow in a shale gas reservoir. An experimental apparatus was designed and set up to measure porosity and permeability at the nanopore scale. The measured properties have been used to determine a diffusion coefficient by classification standard of gas flow regime. To investigate the impact of pressure and pore size, the analysis of diffusion flow was conducted using Knudsen and Fick diffusion coefficients. From the results, it was revealed that Knudsen diffusion coefficient gradually increased with the growth of pressure and pore radius and Fick diffusion coefficient was dependent on the gas molecular diameter and temperature. It was also found that Knudsen diffusion coefficient was equal to Fick diffusion coefficient if pore radius is too small. The study implied that the characteristics of gas diffusion should be implemented by using the diffusion coefficient theory based on gas flow regime in shale gas reservoirs.
Coupling numerical simulation and machine learning to model shale gas production at different time resolutions
在不同时间段用耦合数值模拟与机器学习模拟页岩气生产
Journal of Natural Gas Science and Engineering, Volume 25, July 2015, Pages 380-392
Abstract：Reservoir simulation is the most robust tool for simulating gas production from the desorption controlled and hydraulically fractured shale reservoir. Incorporation of the created massive hydraulic fractures explicitly into the simulation model is the major challenge during the model development and computation phases.
A pattern recognition-based proxy model is our proposed technique to overcome the aforementioned problem by modeling time successive shale gas production at the hydraulic fracture cluster level at different time resolutions (Short-, medium- and long term). Ensemble of multiple, interconnected adaptive neuro-fuzzy systems create the core for the development of the shale proxy models. In this approach, unlike reduced order models, the physics and the space-time resolution are not reduced. Instead of using pre-defined functional forms that are more frequently used to develop response surfaces, a series of machine learning algorithms that conform to the system theory are used.
A history-matched Marcellus shale gas pad with six horizontal laterals and 169 clusters of hydraulic fracture is used as a base case for shale proxy model development. Additionally, several realizations are defined in order to capture the uncertainties inherent in the shale simulation model. The proxy model is validated using a blind simulation run that is not used during the model development process. The developed shale proxy model re-generates the simulation results for methane production for 169 clusters hydraulic fracture in a second with high accuracy (<15% error), thus making a comprehensive analysis of production from shale a practical and feasible option. Moreover, it can be used as an assisted history-matching tool, since it has the capability to scrutinize the solution space and produce the model response to the uncertainty changes very fast.
A new rapid method for shale oil and shale gas assessment
页岩油与页岩气快速评估方法
Fuel, Volume 153, 1 August 2015, Pages 231-239
Abstract: Unconventional hydrocarbons represent the future of fossil fuel supply. Arguably the most exciting unconventional deposits are those provided by shale gas and shale oil, hydrocarbons generated and retained by fine grained sedimentary rocks. Effective exploration for shale gas and shale oil requires screening of large numbers of samples in a time and cost effective manner. The most promising samples are then selected for more sophisticated and time consuming procedures. We have examined a new screening technique for shale gas and shale oil. Pyrolysis-FTIR provides a substantial amount of information related to shale quality in a single analysis including the types of gases present (including methane) and the nature of any liquid hydrocarbons released. Construction of calibration curves allows the rapid determination of gas quantities and the average chain length of aliphatic hydrocarbons present. Application of pyrolysis-FTIR to Carboniferous oil shales from the Midland Valley of Scotland reveal percentage levels of methane. Following pyrolysis at 600 °C, immature Type III kerogen containing shale has relative gas abundances in the order water > carbon dioxide > methane, mature Type I kerogen containing shales have gas abundances that follow the order water > methane > carbon dioxide and post mature Type I kerogen containing shales have relative abundances in the order carbon dioxide > water > methane. Multistep pyrolysis-FTIR reveals carbon speciation and the relative responses at low and high temperatures reflect sample maturity. The new pyrolysis-FTIR technique can provide a relatively simple and labour saving, but information-rich, technique for the assessment of shale oil and shale gas targets.
Scenarios for shale gas development and their related land use impacts in the Baltic Basin, Northern Poland
波兰北部波罗的海盆地页岩气开发及其有关土地利用影响现状
Energy Policy, Volume 84, September 2015, Pages 80-95
Abstract: Scenarios for potential shale gas development were modelled for the Baltic Basin in Northern Poland for the period 2015–2030 using the land allocation model EUCS100. The main aims were to assess the associated land use requirements, conflicts with existing land use, and the influence of legislation on the environmental impact. The factors involved in estimating the suitability for placement of shale gas well pads were analysed, as well as the potential land and water requirements to define 2 technology-based scenarios, representing the highest and lowest potential environmental impact. 2 different legislative frameworks (current and restrictive) were also assessed, to give 4 combined scenarios altogether. Land consumption and allocation patterns of well pads varied substantially according to the modelled scenario. Potential landscape fragmentation and conflicts with other land users depended mainly on development rate, well pad density, existing land-use patterns, and geology. Highly complex landscapes presented numerous barriers to drilling activities, restricting the potential development patterns. The land used for shale gas development could represent a significant percentage of overall land take within the shale play. The adoption of appropriate legislation, especially the protection of natural areas and water resources, is therefore essential to minimise the related environmental impact.
Comment on ‘Life cycle environmental impacts of UK shale gas’ by L. Stamford and A. Azapagic. Applied Energy, 134, 506–518, 2014
英国页岩气生命周期环境影响评价
Applied Energy, Volume 148, 15 June 2015, Pages 489-495
Abstract: In the recent work entitled “Life cycle environmental impacts of UK shale gas” (Applied Energy, 134 (2014) 506–518) Stamford and Azapagic (2014) make a first attempt at quantifying a range of overall lifecycle impacts of shale gas production in the UK. Their analysis led to some very unfavourable comparisons with other energy technologies and concluded that, for three types of impact (depletion of the stratospheric ozone layer, photochemical pollution, and terrestrial eco-toxicity), shale gas is ‘worse’ even than coal as an energy source for generating electricity; furthermore, uncertainties in input data mean that it might also be worse than coal for three additional impacts (on global warming, acidification, and human toxicity). One of their principal inferences is, therefore, that shale gas development in the UK should be subject to stringent environmental regulation, to ensure that it is only developed where it can be demonstrated to regulatory authorities on a well-by-well basis that these and other impacts can be minimized. The present commentary reassesses some of the conclusions reached by this published analysis.
Evolution of water chemistry during Marcellus Shale gas development: A case study in West Virginia
Marcellus页岩气开发过程中的水化学演变：西维吉尼亚实例研究
Chemosphere, Volume 134, September 2015, Pages 224-231
Abstract: Hydraulic fracturing (HF) has been used with horizontal drilling to extract gas and natural gas liquids from source rock such as the Marcellus Shale in the Appalachian Basin. Horizontal drilling and HF generates large volumes of waste water known as flowback. While inorganic ion chemistry has been well characterized, and the general increase in concentration through the flowback is widely recognized, the literature contains little information relative to organic compounds and radionuclides.
This study examined the chemical evolution of liquid process and waste streams (including makeup water, HF fluids, and flowback) in four Marcellus Shale gas well sites in north central West Virginia. Concentrations of organic and inorganic constituents and radioactive isotopes were measured to determine changes in waste water chemistry during shale gas development.
We found that additives used in fracturing fluid may contribute to some of the constituents (e.g., Fe) found in flowback, but they appear to play a minor role. Time sequence samples collected during flowback indicated increasing concentrations of organic, inorganic and radioactive constituents. Nearly all constituents were found in much higher concentrations in flowback water than in injected HF fluids suggesting that the bulk of constituents originate in the Marcellus Shale formation rather than in the formulation of the injected HF fluids. Liquid wastes such as flowback and produced water, are largely recycled for subsequent fracturing operations. These practices limit environmental exposure to flowback.
Techno-economic assessment of industrial CO2 storage in depleted shale gas reservoirs
枯竭页岩气藏中工业二氧化碳储存的技术经济评估
Journal of Unconventional Oil and Gas Resources, Volume 11, September 2015, Pages 82-94
Abstract: The long-term storage of carbon dioxide (CO2) via injection into deep geologic formations represents a promising technological pathway to reducing greenhouse gas emissions to the atmosphere. Geologic storage in deep saline aquifers has been studied extensively, and the injection of CO2 for enhanced oil recovery (EOR) from conventional (porous and permeable) formations has been practiced for decades. This study is focused on developing a preliminary assessment of the economic feasibility of storing CO2 in depleted unconventional natural gas-bearing shale formations. Using a surrogate reservoir model (SRM) and a flexible environment for techno-economic analysis, this paper presents site-scale estimates of long-term CO2 sequestration costs in depleted shale gas formations and discussion of the likely major cost drivers. This analysis focuses on the transportation of CO2 from industrial point sources in the Pennsylvania Marcellus Shale region, and the transition of Marcellus wells from production to CO2 injection. This approach couples techno-economic analysis with reservoir simulation models to estimate costs associated with transportation, injection, CO2 separation and post-injection monitoring of CO2 storage permanence from large industrial point sources in depleted shale-gas reservoirs. We also consider potential revenue from incremental CH4 recovery (effectively enhanced gas recovery) in reservoir scenarios where such production is significant. The techno-economic model boundary includes pipeline transport from an industrial source (excludes the cost of capture of CO2 at that source), site preparation and CO2 flooding operations, and long-term monitoring and post-injection site care (PISC) at the storage site. Under an operational scenario where a Marcellus shale gas well is in primary production for 42 years prior to the initiation of CO2 injection, it is estimated that CO2 could be transported and stored at a levelized cost of $40–$80 per metric tonne, in present value terms. These costs are shown to be highly sensitive to assumptions regarding well spacing, bottomhole pressure, CO2 transport distance and the future price of natural gas. In most of the scenarios considered, transportation and injection costs were dominant factors, while CO2 separation, pore space acquisition and post-injection site care/monitoring did not significantly influence levelized costs.
