Shale Gas Reservoirs Characterization Using Neural Network
基于神经网络的页岩气藏表征
Energy Procedia, Volume 59, 2014, Pages 16-21
Abstract: In this paper, a tentative of shale gas reservoirs characterization enhancement from well-logs data using neural network is established. The goal is to predict the Total Organic carbon (TOC) in boreholes where the TOC core rock or TOC well-log measurement does not exist. The Multilayer Perceptron (MLP) neural network with three layers is implanted. The MLP input layer is constituted with five neurons corresponding to the natural Gamma ray, Neutron porosity and sonic P and S wave slowness. The hidden layer is composed with nine neurons and the output layer is formed with one neuron corresponding to the TOC log. Application to two horizontal wells drilled in Barnett shale formation where the well A is used as a pilot and the well B is used for propagation clearly shows the efficiency of the neural network method to improve the shale gas reservoirs characterization. The established formalism plays a high important role in the shale gas plays economy and long term gas energy production.
Organic matter characteristics and gas generation potential of the Tertiary shales from NW Kutch, India
印度Kutch西北第三纪页岩有机物特征以及生气潜力
Journal of Petroleum Science and Engineering, Volume 124, December 2014, Pages 114-121
Abstract: Geochemical attributes of shale such as the TOC content, thermal maturity and kerogen properties provide useful insights on its gas generation potential. Here, the Tertiary shales interbedded within the lignite sequences of Naredi Formation in North Western Kutch Basin have been studied to understand the abundance, thermal maturity and quality of kerogen in the shale׳s organic matter. The samples have been collected from the opencast mines of Matanomadh, Panandhro and drill site of Umarsar, where the Naredi Formation is exposed. Open system pyrolysis of the Tertiary shales was carried out using the Rock Eval 6 pyrolyser. The results show the S1 (free hydrocarbons) and S2 (hydrocarbons cracked from kerogen) values to range between 0 and 3.71 mg HC/g rock and 0.02 and 91.13 mg HC/g rock respectively. The Tmax (temperature at the highest yield of S2) ranges between 383 and 452 °C. The Total Organic Carbon (TOC) content varies between 0.35% and 30.92% and the hydrogen index (HI) values lie between 3 and 358 mg HC/g TOC.
In general the shales, particularly the subsurface cores from Matanomadh and Umarsar indicate very good to excellent organic richness. Based on the hydrogen and oxygen indices, the organic matter is characterized by Type-II and Type-II/III kerogen. The variation of HI vs Tmax suggests immature stage for the generation of hydrocarbons. The shales interbedded within the Naredi Formation can have high potential for gas generation in areas where the formation is buried deeply and has attained sufficient thermally maturity to generate the gas.
Comparisons of pore size distribution: A case from the Western Australian gas shale formations
气孔分布比较：澳大利亚西部气页岩地层实例研究
Journal of Unconventional Oil and Gas Resources, Volume 8, December 2014, Pages 1-13
Abstract: Pore structure of shale samples from Triassic Kockatea and Permian Carynginia formations in the Northern Perth Basin, Western Australia is characterized. Transport properties of a porous media are regulated by the topology and geometry of inter-connected pore spaces. Comparisons of three laboratory experiments are conducted on the same source of samples to assess such micro-, meso- and macro-porosity: Mercury Injection Capillary Pressure (MICP), low field Nuclear Magnetic Resonance (NMR) and nitrogen adsorption (N2). High resolution FIB/SEM image analysis is used to further support the experimental pore structure interpretations at sub-micron scale.
A dominating pore throat radius is found to be around 6 nm within a mesopore range based on MICP, with a common porosity around 3%. This relatively fast experiment offers the advantage to be reliable on well chips or cuttings up the pore throat sizes >2 nm. However, nitrogen adsorption method is capable to record pore sizes below 2 nm through the determination of the total pore volume from the quantity of vapour adsorbed at relative pressure. But the macro-porosity and part of the meso-porosity is damaged or even destroyed during the sample preparation.
BET specific surface area results usually show a narrow range of values from 5 to 10 m2/g. Inconsistency was found in the pore size classification between MICP and N2 measurements mostly due to their individual lower- and upper-end pore size resolution limits. The water filled pores disclosed from NMR T2 relaxation time were on average 30% larger than MICP tests. Evidence of artificial cracks generated from the water interactions with clays after re-saturation experiments could explain such porosity over-estimation. The computed pore body to pore throat ratio extracted from the Timur–Coates NMR model, calibrated against gas permeability experiments, revealed that such pore geometry directly control the permeability while the porosity and pore size distribution remain similar between different shale gas formations and/or within the same formation. The combination of pore size distribution obtained from MICP, N2 and NMR seems appropriate to fully cover the range of pore size from shale gas and overcome the individual method limits.
Surface water geochemical and isotopic variations in an area of accelerating Marcellus Shale gas development
玛西纳页岩气开发区域地表水地球化学及同位素变化
Environmental Pollution, Volume 195, December 2014, Pages 91-100
Abstract: Water samples were collected from 50 streams in an area of accelerating shale gas development in the eastern U.S.A. The geochemical/isotopic characteristics show no correlation with the five categories of Marcellus Shale production. The sub-watersheds with the greatest density of Marcellus Shale development have also undergone extensive coal mining. Hence, geochemical/isotopic compositions were used to understand sources of salinity and effects of coal mining and shale gas development in the area. The data indicates that while some streams appear to be impacted by mine drainage; none appear to have received sustained contribution from deep brines or produced waters associated with shale gas production. However, it is important to note that our interpretations are based on one time synoptic base flow sampling of a few sampling stations and hence do account potential intermittent changes in chemistry that may result from major/minor spills or specific mine discharges on the surface water chemistry.
Slip in natural gas flow through nanoporous shale reservoirs
天然气流通过纳米孔隙页岩储层的滑脱效应
Journal of Unconventional Oil and Gas Resources, Volume 7, September 2014, Pages 49-54
Abstract: It is observed that to assess the shale gas flow in nanopores the recent literature relies on the flow regimes discovered by Tsien (1946). Tsien classified fluid flow systems based on the range of Knudsen number (Kn), the ratio of the mean free path to average pore diameter. The flow regimes are: continuum flow for Kn < 0.01, slip flow for 0.001 < Kn < 0.1, transition regime for 0.1 < Kn < 10, and free molecule flow for Kn > 10. This scale was originally developed from the physics of rarefied gas flow. Is it then appropriate to use the classical Kn scale to develop models of shale gas flow in tight reservoirs where the nanopores are in the range of 1–1000 nm, and pore pressures can be as high as 10,000 psi? The present work explores answers to this question. We provide an analysis based on classical slip flow model. We validate the Kn scale incorporating PVT (Pressure–Volume–Temperatures) schemes. Our results show that in very tight shale (order of 1 nm pore size) there can be substantial slip flow based on the characteristics of pore walls in the reservoirs of high temperatures and low pressures. In the case of large pore size (∼1000 nm) there is zero slip flow irrespective of temperature and pressure. The Kn scale which was designed for rarefied gases cannot be true for the natural gas flow regimes at all temperatures and pressures. Therefore we must be careful in referring this scale to model the shale gas flows. Results presented here from simple calculations agree with those obtained from expensive molecular dynamics (MD) simulations and laboratory experiments.
Paleozoic oil/gas shale reservoirs in southern Tunisia: An overview
突尼斯南部古生代油/气页岩储藏状况综述
Journal of African Earth Sciences, Volume 100, December 2014, Pages 450-492
Abstract: During these last years, considerable attention has been given to unconventional oil and gas shale in northern Africa where the most productive Paleozoic basins are located (e.g. Berkine, Illizi, Kufra, Murzuk, Tindouf, Ahnet, Oued Mya, Mouydir, etc.). In most petroleum systems, which characterize these basins, the Silurian played the main role in hydrocarbon generation with two main ‘hot’ shale levels distributed in different locations (basins) and their deposition was restricted to the Rhuddanian (Lllandovery: early Silurian) and the Ludlow–Pridoli (late Silurian). A third major hot shale level had been identified in the Frasnian (Upper Devonian). Southern Tunisia is characterized by three main Paleozoic sedimentary basins, which are from North to South, the southern Chotts, Jeffara and Berkine Basin. They are separated by a major roughly E–W trending lower Paleozoic structural high, which encompass the Mehrez-Oued Hamous uplift to the West (Algeria) and the Nefusa uplift to the East (Libya), passing by the Touggourt-Talemzane-PGA-Bou Namcha (TTPB) structure close to southern Tunisia. The forementioned major source rocks in southern Tunisia are defined by hot shales with elevated Gamma ray values often exceeding 1400 API (in Hayatt-1 well), deposited in deep water environments during short lived (c. 2 Ma) periods of anoxia. In the course of this review, thickness, distribution and maturity maps have been established for each hot shale level using data for more than 70 wells located in both Tunisia and Algeria. Mineralogical modeling was achieved using Spectral Gamma Ray data (U, Th, K), SopectroLith logs (to acquire data for Fe, Si and Ti) and Elemental Capture Spectroscopy (ECS). The latter technique provided data for quartz, pyrite, carbonate, clay and Sulfur. In addition to this, the Gamma Ray (GR), Neutron Porosity (ΦN), deep Resistivity (Rt) and Bulk Density (ρb) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete geochemical review has been undertaken from published papers and unpublished internal reports to better assess these important source intervals.
Environmental risks of shale gas development in China
中国页岩气开发的环境风险
Energy Policy, Volume 75, December 2014, Pages 117-125
Abstract: Shale gas development in China can generate great potential economic benefits, but also poses serious environmental risks. In this paper, we offer a macro assessment of the environmental risks of shale gas development in China. We use the US experience to identify the nature of shale gas development activities and the types of potential burdens these activities may create. We then review the baseline environmental conditions and the effectiveness of environmental regulations in China and discuss the implications of these China-specific factors for risk assessment. We recommend China to conduct a strategic environmental assessment and to consider sector-specific environmental regulations.
Life cycle environmental impacts of UK shale gas
英国页岩气的生命周期环境影响
Applied Energy, Volume 134, 1 December 2014, Pages 506-518
Abstract: Exploitation of shale gas in the UK is at a very early stage, but with the latest estimates suggesting potential resources of 3.8 × 1013 cubic metres – enough to supply the UK for next 470 years – it is viewed by many as an exciting economic prospect. However, its environmental impacts are currently unknown. This is the focus of this paper which estimates for the first time the life cycle impacts of UK shale gas, assuming its use for electricity generation. Shale gas is compared to fossil-fuel alternatives (conventional gas and coal) and low-carbon options (nuclear, offshore wind and solar photovoltaics). The results suggest that the impacts range widely, depending on the assumptions. For example, the global warming potential (GWP100) of electricity from shale gas ranges from 412 to 1102 g CO2-eq./kWh with a central estimate of 462 g. The central estimates suggest that shale gas is comparable or superior to conventional gas and low-carbon technologies for depletion of abiotic resources, eutrophication, and freshwater, marine and human toxicities. Conversely, it has a higher potential for creation of photochemical oxidants (smog) and terrestrial toxicity than any other option considered. For acidification, shale gas is a better option than coal power but an order of magnitude worse than the other options. The impact on ozone layer depletion is within the range found for conventional gas, but nuclear and wind power are better options still. The results of this research highlight the need for tight regulation and further analysis once typical UK values of key parameters for shale gas are established, including its composition, recovery per well, fugitive emissions and disposal of drilling waste.
A new tool for prospect evaluation in shale gas reservoirs
页岩气藏前景评估的新方法
Journal of Natural Gas Science and Engineering, Volume 18, May 2014, Pages 90-103
Abstract: In recent years, unconventional gas (particularly shale gas – SG) has played an increasing role in satisfying gas demand both in North America and beyond. Despite extensive development, minimal work has been done to develop tools and methodologies for SG prospect analysis. Due to the complexity and variability among SG prospects, it is crucial to not only investigate all possible prospects, but also to investigate all areas within the selected prospect to pick pilot locations which offer the best potential for commercial success. In addition, due to the complexity of SG reservoirs, many authors have suggested that stochastic techniques should be used to assist in quantifying the risk and uncertainty of the analysis.
This paper discusses a new tool that was developed specifically for SG exploration and development. This tool combines the latest production data analysis and rate forecasting techniques with a simple, yet rigorous stochastic method for analyzing pilot well locations. The paper discusses the rate forecasting techniques used in the tool, as well as the tool development and application. Both simulated and field cases are provided to demonstrate the new methodology. This paper is an extension of the work presented by Williams-Kovacs and Clarkson (2011).
Impact of Rock Fabric on Water Imbibition and Salt Diffusion in Gas Shales
气页岩中岩构造对吸水性及盐扩散的影响
International Journal of Coal Geology, December 2014
Abstract: Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, clay swelling and osmotic potential on imbibition behavior.
We systematically measure and compare the imbibition rates of fresh water and oil into wet/dry and confined/unconfined rock samples from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that initial water saturation decreases the water uptake of shale samples. But, it has no effect on oil imbibition rates. The results also suggest that confining the shale samples decreases the water imbibition rate, parallel to the lamination. However, it has a negligible effect on water uptake, perpendicular to the lamination. Furthermore, confining does not significantly affect the ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. The liquid imbibition and ion diffusion rates along the lamination are higher than those against the lamination. Surprisingly, previous experiments on crushed shale samples show that the oil uptake of crushed packs is higher than their water uptake [73]. The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by BSE images and complete spreading of oil on fresh break surfaces of the rock.
