Shale Sources Research Articles

鄂西宜昌地区页岩气勘探发现对MVT铅锌矿成矿的指示意义

The coupling relationship between hydrocarbon accumulation and the involvement of organic matter in metal mineralization has been a frontier scientific question in recent years. On the basis of the petrography and Raman spectral analysis of fluid inclusions, high-density methane inclusions were discovered in the samples of quartz and calcite veins from Sinian Doushantuo shales, Lower Cambrian Niutitang shales, and MVT (Mississippi Valley type) lead-zinc deposit of Sinian Dengying Formation in Yichang area. The Raman scatter peak v of methane inclusions was applied to calculate the density of pure methane inclusions, and the ore-forming ages of MVT lead-zinc deposit were determined by using Rb-Sr and Sm-Nd isochron dating. The density of methane inclusions trapped in the quartz veins within the Doushantuo shales of well EYY 1 mainly ranges from 0.237 to 0.278 g/cm, and the density of methane inclusions trapped in the calcite veins within the Hejiaping MVT lead-zinc deposit mainly ranges from 0.213 to 0.271 g/cm, which signifies methane inclusions of high density. Paragenetic mineral association sphalerite and galena within the Hejiaping lead-zinc deposit have a Rb-Sr isochron age of 189.1±1.8 Ma, and calcite within the Hejiaping lead-zinc deposit yields a Sm-Nd isochron age of 189.9±2.0 Ma, which indicates is the mineralization of Hejiaping lead-zinc deposit was closely related to the Yanshanian tectonic compressions. The Sr/Sr values of the paragenetic mineral association (0.711 92) and calcite (0.712 03-0.712 27) indicate that the ore-forming fluids of the Hejiaping lead-zinc deposit were derived largely from shale sources. The high-density methane trapped in fluid inclusions within the Hejiaping lead-zinc deposit was most likely derived from the high-density overpressure methane generated by the Doushantuo shales and/or Niutitang shales. The discovery of high-density methane inclusion in the shale gas layer and MVT lead-zinc deposit, and the determination of ore-forming ages of MVT lead-zinc deposit provide new evidence for the study of organic matter participation in the mineralization of MVT lead-zinc deposit.

Method development for rapid quantification of Rn-222 in surface water and groundwater.

Understanding the risks of a developing unconventional hydrocarbons industry, including shale gas, to the chemical quality of surface water and groundwater involves firstly establishing baseline compositions against which any future changes can be assessed. Contaminants of geogenic origin are of particular interest and radon has been identified as one potential contaminant from shale sources. Robust measurement and monitoring of radon in water at environmental concentrations is essential for ensuring protection of water sources and maintaining public confidence. Traditional techniques for Rn-222 determination in water, such as inference by gamma spectrometry and direct alpha counting, are impractical for direct field measurement, and the relatively short half-life of Rn-222 (~ 3.82days) means that longer analytical protocols from field to the laboratory may result in greater uncertainty for Rn-222 activity. Therefore, a rapid and low-cost method would be beneficial. We have developed and refined a laboratory procedure for Rn-222 monitoring using liquid scintillation counting (LSC). The accuracy of Rn-222 activities obtained via this procedure was evaluated by the analysis of almost 200 water samples collected from streams and boreholes as part of a detailed baseline investigation in the Vale of Pickering, Yorkshire, one potential location for future shale gas exploration. LSC was preferred for measurement of Rn-222 and had comparable accuracy to gamma spectrometry and direct alpha counting. The methodology provided a rapid, portable and low-maintenance option relative to the two established techniques and is shown to be a favourable choice for the measurement of radon in surface water and groundwater at environmental concentrations.

South Africa After Paris—Fracking Its Way to the NDCs?

South Africa faces the triple challenge of (a) fueling its economic development by meeting the rapidly growing energy demand; (b) increasing the reliability of its power system; and (c) letting domestic greenhouse gas emissions peak between 2020 and 2025 in line with its pledge to the UNFCCC under the Paris agreement. Recently discovered domestic shale gas reserves are currently under evaluation as a potential new energy source, to provide clean, reliable and cheap electricity while mitigating greenhouse gas emissions. But, the impact of shale gas on greenhouse gas emissions is far from settled. In order to evaluate if shale gas can play a viable role in solving South Africa’s energy dilemma, we apply a country-level version of the integrated assessment model MESSAGE to analyze and quantify the interdependence between shale gas extraction and climate change mitigation e_ort regarding the South African energy pathways and its domestic greenhouse gas emissions. Our results illustrate, that low cost shale gas can lower the overall energy system costs compared to the no-shale-gas counterfactual. At the same time, a system with abundant low cost natural gas from shale sources requires a stronger carbon price signal compared to the no-shale-gas scenarios in order to achieve the same desired mitigation goals. Therefore, reaching the mitigation goals might be more economically achievable utilizing low cost shale gas in combination with a more stringent climate policy measure compared to a no-shale-gas scenario.

Small-Field Approach Holds Promise for Operators in Southeast Asia

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186434, “Small Is Beautiful: Why Small Fields Are the Next Big Thing in Southeast Asia and How to Capitalize on Them,” by Arnold Volkenborn, Andrew Lea-Cox, SPE, and Bo Sun, Accenture Strategy Energy, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed. This paper shows how a new approach to small fields could unlock more than twice the net present value (NPV) of larger conventional fields in Southeast Asia at a similar level of capital expenditure (CAPEX). Capturing this value, though, will require a fundamental change in the operating models of operators in the region. The small-field approach focuses on margin maximization instead of recovery and productivity maximization. Introduction Southeast Asia has attracted sizeable foreign interest in recent years after weathering the global financial crisis while establishing strong manufacturing bases, expanding domestic infrastructure, and stabilizing financial markets. These developments fueled economies and continued to push energy demand higher. However, Southeast Asia is facing its own challenges. Oil and gas companies in the region have been tasked with meeting domestic demand through local petroleum resources since the 1990s. Although companies have continued to discover new fields, efforts were insufficient to meet the growing demand, causing Southeast Asia to become a net importer in the early 2000s. Moreover, the industry has accepted a new oil price norm approximately 60% lower than June 2014 levels. As some early signs of recovery emerge, another disruption is on the horizon: Because of a combination of technological and socio economic factors, demand for oil is expected to peak as early as 2030. Concurrently, on the supply side, assets such as shale and nonhydrocarbon sources (e.g., solar and wind) are eating increasingly into oil’s share of the energy market. These factors are forcing exploration and production (E&P) companies to cut capital and operational spending significantly and refocus their portfolios on core areas of advantage. Investors now are wary of locking up capital in long-cycle megaprojects. Given the smaller size of discoveries, the need for decreased spending, and the demand for shorter-cycle projects, significant market opportunities exist for any player who can make a small-field business model work. Potential of Small Fields The future of Southeast Asia is in small fields, defined here as fields with less than 100 million BOE of reserves. First, the region is scattered with such discoveries and prospects. Second, and more importantly, a small-field approach addresses the current investor preference for high-margin, short-cycle projects. While technically difficult, small fields have great potential in terms of unlocking barrels to fill domestic demand and producing higher returns for capital-constrained companies. Extent of Small Fields in Southeast Asia. The average size of discoveries in Southeast Asia has decreased to approximately 35 million BOE in the last 5 years, compared with two to three times that in the 1970s–1990s.

Airborne Quantification of Methane Emissions over the Four Corners Region.

Methane (CH4) is a potent greenhouse gas and the primary component of natural gas. The San Juan Basin (SJB) is one of the largest coal-bed methane producing regions in North America and, including gas production from conventional and shale sources, contributed ∼2% of U.S. natural gas production in 2015. In this work, we quantify the CH4 flux from the SJB using continuous atmospheric sampling from aircraft collected during the TOPDOWN2015 field campaign in April 2015. Using five independent days of measurements and the aircraft-based mass balance method, we calculate an average CH4 flux of 0.54 ± 0.20 Tg yr-1 (1σ), in close agreement with the previous space-based estimate made for 2003-2009. These results agree within error with the U.S. EPA gridded inventory for 2012. These flights combined with the previous satellite study suggest CH4 emissions have not changed. While there have been significant declines in natural gas production between measurements, recent increases in oil production in the SJB may explain why emission of CH4 has not declined. Airborne quantification of outcrops where seepage occurs are consistent with ground-based studies that indicate these geological sources are a small fraction of the basin total (0.02-0.12 Tg yr-1) and cannot explain basinwide consistent emissions from 2003 to 2015.

Shale gas in Poland: An analysis of tax mechanismsand dynamic interactions

(ProQuest: ... denotes formulae omitted.)IntroductionTo date, not a single cubic meter of shale gas has been extracted and sold in Europe. While the substance still sits deep in the ground, it has already fuelled a fierce debate, protests, hopes and fears across the continent. Poland is the forerunner of exploration of natural gas from unconventional (shale rock) deposits. Nevertheless, little economic research has been conducted on the topic of shale gas in Poland. This exploratory study hopes to contribute to the scholarship on the topic.The aim of this article is to approach the study of shale gas from an economic perspective, with welfare at the centre of the analysis, and to deliver policy recommendations for the Polish government on the taxation of the shale gas extracting firms in Poland.The key result of the static analysis is that is that lump sum tax is the first best of all taxation methods. The second best option for taxation is a combination of the CIT and a windfall profit tax. From the dynamic perspective, this research argues that Gazprom can remain the market leader thanks to the sequential character of the competition in the Polish natural gas market, but this would not have negative welfare effects.This study is structured in the following way: section two introduces the topic of shale gas in Poland, section three elaborates on the methods, section four provides an analysis of the tax mechanisms from a static perspective, section five looks at the dynamic effects and sections six concludes the research.1.Shale gas in PolandThe Polish government initially offered the licenses to explore, or explore and extract, shale gas in the form of concessions. The second license type, to explore and extract, was introduced in order to simplify the market regulation and to attract investors. For a low price firms could purchase the right to explore and extract, regardless of the findings. Concessions are individual parcels of land. The price of each concession is determined by its size multiplied by a single rate that the Polish government sets per square kilometre (km2). A single rate applies to all concessions in the country. For exploration only, the price per km2 had been set at PLN 105.811 and for exploration and extraction PLN 211.622. In addition, the firm that bought the license only for the exploration process had the pre-emptive right to upgrade the license to extraction of shale gas. There were two reason behind this design. First was lack of knowledge about the quantity and quality of natural gas in the Polish shale rock formations. Second, the investors, not the taxpayers, bore the cost of exploration and the associated risk. Shifting the costs and risk associated with exploration process on investors was compensated by the government to the firms in the form of the pre-emptive right to purchase a license for extraction and the single exploration/extraction licenses. A new law, introduced in 2014, has combined previous types of concession into one, in a further effort to simplify access to the market. In all cases the legal set- up has ruled out auctions at the extraction stage. For this reason the Polish government has turned to taxation as a method to collect revenue from the potential shale gas extraction and sales. In the Polish government's view the 19 per cent profit tax is insufficient. Warsaw decided, in the 2014 change of law, to raise the potential revenue from taxation of shale gas firms by adding a complementary tax on fossil fuels, that depends on the profitability of the source, and can amount to 0, 12,5 or 25 per cent and also an additional tax of 1,5 per cent on the total value of extracted natural gas from shale sources. Nevertheless, collection of the complementary tax has been suspended until year 2020, in an attempt to stimulate the industry. Possibly, taxation of shale gas will be adjusted once again in the future. Without certainty about tax regulation and the size of the tax burden, investors are reluctant to invest in exploration or move from exploration to extraction; what harms consumers of natural gas in Poland. …

A Natural Gas Severance Tax—An Economic Analysis

AbstractThis study estimates the economic effects of a severance tax on the market for natural gas produced from shale sources using non‐conventional extraction methods, such as horizontal drilling and fracking. Results suggest that a severance tax of 5 % would increase the price of natural gas by as much as 3.82 % and decrease gas extraction by an estimated 1.16 % to a value of 9.52 %. If applied to the Commonwealth of Pennsylvania in the United States, a 5 % severance tax is estimated to raise between US $443 and $486 million per year in public revenue. The marginal deadweight loss associated with a 5 % severance tax is estimated between 1.27 % and 12.85 % of the last dollar earned. The burden of this tax falls on both producers and consumers and depends upon the underlying assumptions made regarding the price responsiveness of consumers and producers. Under plausible assumptions, a family consuming 1000 MMcfs (≈2.8×104 m3) per year of natural gas is estimated to pay an additional $100 per year after the implementation of a 5 % severance tax.

AN OVERVIEW OF SHALE OIL UTILIZATION

The contribution of shale oil as raw material to the mineral oil processing industry has been increased due to the worldwide energy demand. This review article discusses the principles of shale oil processing using rotary dry distillation boilers and the practical applicability of shale oil. The complete utilization of oil shale sources results in good economic and social benefits.

Comments: The Energy Outlook

Editor's column Global demand shows no signs of slowing, increasing another 2 million B/D in 2011. Both international and national oil companies are anticipating continued strong energy demand and sustained reliance on fossil fuels as the energy product of choice. Two new long-term outlooks agree that global population growth and rising incomes will propel energy demand, primarily in developing countries. The most significant shift in the energy mix going forward is increasing reliance on natural gas and a decline in coal use for electricity. BP’s Energy Outlook 2030 predicts that world energy consumptions will grow 1.6% a year from 2010 to 2030, although energy efficiency will improve sharply, restraining overall growth in energy consumption. Almost all of the growth will come from non-OECD countries. Use of natural gas and nonfossil fuels will gain at the expense of coal, with gas expected to meet 31% of the growth in global consumption. Although heavy reliance on fossil fuels will continue, gas consumption also will take market share away from oil. The report forecasts that oil demand growth will come largely from China, India, and the Middle East. Supply for meeting that expected growth in demand will come primarily from OPEC countries, with production increases in natural gas liquids and conventional crude from Saudi Arabia and Iraq. ExxonMobil recently extended its long-term energy forecast to 2040 for the first time. The Outlook for Energy: A View to 2040 predicts that global demand will be about 30% higher in 2040 compared with today, with demand in developing countries rising about 60%. “Less carbon-intensive fuels, particularly natural gas, gain market share, while coal peaks and begins a decline for the first time in modern history,” the report says. The shale revolution continues, as the report predicts that natural gas from shale and similar sources will make up roughly a third of total global gas production by 2040. Executives speaking at last month’s International Petroleum Technology Conference in Bangkok, Thailand, generally agree with these assessments. Fossil fuels will remain the dominant fuel choice for years to come, but their development will require increased technical capability and efficiency to meet global demand, panelists at the conference executive plenary session concluded. The future will demand a “higher intensity” of E&P efforts, said Nasser Al-Jaidah, chief executive officer of Qatar Petroleum. The industry must give assurances that it can develop resources to meet world demand and must make a commitment to introducing new technologies that increase recovery factors. Additionally, the industry must confirm that it can operate in more efficient ways to mitigate greenhouse gas emissions. Several game-changing technical opportunities exist, said Dato Wee Yiaw Hin, executive vice president of E&P at Petronas, among them increasing recovery factors through enhanced oil recovery, carbon capture and sequestration, Arctic exploration, and the development of biofuels. Speakers at the conference agreed that the growth in shale supplies is promising, but the sector will not develop as quickly as it did in the US. The main hurdle for shale is acceptability, both from governments and the public.

Nitrogen compound distribution in middle distillate fuels derived from petroleum, oil shale, and tar sand sources

Nitrogen compound distribution in middle distillate fuels derived from petroleum, oil shale, and tar sand sources

The occurrence and correlation of oils and Namurian source rocks in the Liverpool Bay-North Wales area

Abstract Along the northeast coast of Wales, the Holywell Shale is a significant lithological unit of about 150 m thickness. In the field, the Holywell Shale appears to be lithologically fairly uniform. Geochemical analysis of field samples has demonstrated highly variable features within the Holywell Shale. These pertain to organic richness and hydrocarbon source potential. Some samples exhibit good to rich potential for oil and gas, with extractable hydrocarbons akin to those of a light or medium gravity crude oil. Richer examples also exhibit higher hydrogen indices. These data point to oil-prone sources which have realised some of their potential. By contrast, the other samples taken from the section, whilst not poor in organic carbon, have low S 1 and S 2 and HI signatures. It is anticipated, from the data collected that cyclicity is present within the Holywell Shale sediments. The isotope geochemical data also highlights another, more gradual variation. Sources towards the base of the Holywell Shale formation have generated hydrocarbons which are isotopically lighter than those from the middle and upper sections of the formation. This is attributed to middle/upper sections being more proximal to land and consequently, having higher proportions of terrestrially derived organic matter. Two oils (110/13–10 and 110/15–6) from the Douglas and Lennox fields discovered within the Liverpool Bay area have been analysed. Although the two oils are isotopically similar, chromatography analyses reveal that one oil comprises two hydrocarbon phases whereas the other oil has three envelopes. Extracts taken from the Lower Holywell Shale sources and Holywell bitumen are isotopically similar to both oils. Organically rich sources from higher up in the Holywell Shale formation yield more condensate-like hydrocarbons upon extraction and are isotopically heavier than the oils.

Chemical composition and evolution of the upper continental crust: Contrasting results from surface samples and shales

The average chemical composition of juvenile upper continental crust (UC) as a function of age is estimated from chemical analyses, geologic maps, stratigraphic sections and isotopic ages. High plutonic/supracrustal ratios in Archean UC may reflect in part a different mode of crustal formation prior to 2.5 Ga. Greenstones show an increase in felsic volcanics and graywackes in post-Archean successions, a drop almost to zero in the proportion of komatiites at the Archean-Proterozoic (A/P) boundary, and an increase in the proportion of andesites in the Phanerozoic. Compared to the Early Archean, Late and post-Archean UC are depleted in Mg, Cr, Ni and Co, and post-Archean UC is enriched in LILE (large-ion lithophile elements; K, Rb, Ba, Th, U), HFSE (high field strength elements; Ti, P, Zr, Hf, Nb, Ta, Y), and HREE (heavy rare-earth elements). Negative Eu anomalies characterize UC of all ages, although they are relatively small in Archean UC. Cratonic shales show the same secular compositional changes as UC with the following important exceptions: At the A/P boundary, only shales show a decrease in Fe, V and Sc and an increase in Na, Ca and Sr, and only UC shows a significant increase in HREE and Y. Although post-Archean UC has a larger Eu anomaly than Archean UC, it is clear that both Archean UC and Archean shales have negative Eu anomalies, and that shales give only a weak indication of an increasing Eu anomaly in UC formed after the Archean. In both UC and shales at the A/P boundary, Cr/Th, Ni/Co and Co/Th ratios decrease, whereas the Th/U ratio increases only in shales and not in UC. The lack of HREE depletion and the high Fe, V and Sc contents of Archean shales indicate these shales were not derived from sources similar in composition to exposed Archean UC. The shale sources, which are now removed by erosion, must have been composed largely of basalt (± komatiite) (60%) and granite (40%), with little contribution from HREE-depleted TTG (tonalite-trondhjemite-granodiorite), which now dominates in Archean exposures. This suggests strong vertical zonation in the Archean continents with granites intruded into greenstones at very shallow levels. Compositional changes in UC or/and shales at the A/P boundary can be explained in one of the four ways: (1) a greater amount of basalt and komatiite in Archean UC (high Cr and Ni in Archean UC and shales); (2) garnet/amphibole fractionation during production of TTG by partial melting of hydrous basaltic crust (low HREE and Y in Archean UC); (3) change in TTG magma source from descending slab or thickened crust to metasomatized mantle wedge (increase in LILE and LREE in post-Archean UC and shales); and (4) a decrease in the intensity of chemical weathering after the Archean (increase in Na, Ca and Sr in post-Archean shales).

Microbial Contributions to Soluble and Volatile Arsenic Dynamics in Retorted Oil Shale

AbstractArsenic volatilization and solubilization from samples of Paraho and Lurgi retorted shale were evaluated with and without added soybean meal [Glycine max (L.) Merr.], dimethylarsinic acid (DMAA), methanearsonic acid (MAA), and sodium arsenate (SA) in 12‐week experiments. Using a Paraho process shale from an experimental reclamation site in western Colorado, As was only volatilized when nutrients were present, using 23°C incubation. Organic As forms added at 267 × 10−6 mol As kg−1 shale tended to remain more in solution, and were volatilized to a greater extent (45.7 and 6.4 × 10−6 mol kg−1 shale as DMAA and MAA, respectively) than observed with less soluble SA or innate As. Soluble As dynamics were also influenced by nutrient availability. With added DMAA, soluble As levels decreased over the course of the experiment, and decreases followed by rerelease were observed with MAA and SA. The low initial levels of soluble innate As increased slightly over the course of the experiment. In contrast, without nutrients present, other than with added DMAA, the soluble As levels decreased. Incubation at 45°C resulted in a marked reduction of As mobilization, and after heat sterilization, no As mobilization could be observed. Addition of an unsterilized shale inoculum led to a reestablishment of these As mobilization processes in the sterilized samples. In addition, As mobilization was inhibited under anaerobic conditions. With a sample of Lurgi process shale, mobilization in the presence of nutrients was observed, but As volatilization could not be detected, suggesting that variations in oil shale sources and retorting may influence microbial As mobilization. These results suggest that measurable amounts of As can be mobilized from some retorted shale samples, if nutrients are available and environmental conditions allow these processes to occur.