Formation Of Natural Gas Research Articles

Investigation of Mixture Formation and Flammability of Natural Gas and Diesel under Dual Fuel Operating Conditions in the Limits of Flame-quenching and Knocking

Investigation of Mixture Formation and Flammability of Natural Gas and Diesel under Dual Fuel Operating Conditions in the Limits of Flame-quenching and Knocking

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands, Arctic Russia

A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window.

Prospects for shale development outside the USA: evaluating nations' regulatory and fiscal regimes for unconventional hydrocarbons

Pursuant to a generous Association of International Petroleum Negotiator (AIPN) 2014 Summer Research Award, this article identifies, evaluates and compares the legal and fiscal rules, regulations and incentives necessary for countries with significant shale petroleum and natural gas formations to attempt to replicate the boom that is ongoing in the USA. As others have pointed out,1 several legal, tax, and operational barriers can impair duplication of the US shale revolution in similarly endowed nations. This article identifies key factors responsible for the surge in US shale production, distill the fundamental forces from the US experience that are applicable to any jurisdiction, and evaluate and compare how several countries fare in this vein. The report also identifies avenues for reform and innovative policies that could be applied in other jurisdictions.

Hydrogen isotope characteristics of thermogenic methane in Chinese sedimentary basins

The hydrogen isotope composition of methane is an important parameter in natural gas research and provides complementary information to that provided by carbon isotopes. The stable hydrogen isotope ratios of 313 natural gas samples from six of China’s sedimentary basins are used to evaluate the factors that influence the stable hydrogen isotopic composition of methane. An important factor is the δD of organic matter in hydrocarbon source rocks, which is influenced by the sedimentary environment and type of organic matter. Natural gases generated from sapropelic organic matter have relatively less negative δDCH4, while natural gases generated from humic organic matter have relatively more negative δDCH4. The other factor is thermal maturity. Increased thermal maturity leads to δDCH4 becoming less negative and there exists a two stage linear relationship between the δDCH4 and the logarithm of the vitrinite reflectance (Ro) value for natural gases generated from type III kerogen. The third factor is the environmental conditions of the aqueous medium in the original depositional environment and after sedimentation. Elemental hydrogen from water participates in biochemical processes as organisms grow and is exchanged during the sedimentation and diagenesis of organic matter as well as maturity process of kerogen to generate gases. The influence of the aqueous medium on δDCH4 after formation of natural gases can be ignored. Among these factors, the aqueous medium is the key constraining factor. The δDCH4 in natural gases can be combined with the use of stable carbon isotopic composition to identify the origins of natural gases and to aid gas-source correlations.

Effect of CVD graphene on hydrate formation of natural gas

In this study, graphene nano-sheets were grown and synthesized on copper foils and the structure was analyzed with XRD, FTIR and SEM. After that, 1 wt% low-layer graphene nano-sheets were added to water and stabilized by sodium dodecyl sulfate (SDS). Prepared nano-fluid was then used in hydrate formation of natural gas at 1000 psig and 4 °C. The results were compared with a SDS/water system and observed that graphene nano-sheets had reduced the dissolution time 19.2 %, induction time 54.7 % and the amount of gas storage is increased 7.6 %. Hydrate stability test showed that the hydrate stability is also increased 5.9 %.

Gás "de xisto" no Brasil: uma necessidade?

Nos últimos anos cresceu o número de defensores do uso do gás "de xisto" como a melhor alternativa para baratear a produção de energia no Brasil. Este texto apresenta a formação de gás natural não convencional em rochas sedimentares no Brasil, bem como o fraturamento hidráulico e seus impactos socioambientais. Por fim, pondera sobre a necessidade de utilizar essas reservas no Brasil, já que a questão central é discutir o uso da energia no país.

Kerogen maturation data in the Uinta Basin, Utah, USA, constrain predictions of natural hydrocarbon seepage into the atmosphere

Natural seepage of methane from the lithosphere to the atmosphere occurs in regions with large natural gas deposits. According to some authors, it accounts for roughly 5% of the global methane budget. I explore a new approach to estimate methane fluxes based on the maturation of kerogen, which is the hydrocarbon polymer present in petroleum source rocks and whose decomposition leads to the formation of oil and natural gas. The temporal change in the atomic H/C ratio of kerogen lets us estimate the total carbon mass released by it in the form of oil and natural gas. Then the time interval of active kerogen decomposition lets us estimate the average annual formation rate of oil and natural gas in any given petroleum system, which I demonstrate here using the Uinta Basin of eastern Utah as an example. Obviously, this is an upper bound to the average annual rate at which natural gas seeps into the atmosphere. After adjusting for biooxidation of natural gas, I conclude that the average annual seepage rate in the Uinta Basin is not greater than (3100 ± 900) tonne yr−1. This is (0.5 ± 0.15)% of the total flux of methane into the atmosphere over the Basin, as measured during aircraft flights. I speculate about the difference between the regional 0.5% and the global 5% estimates.

Link between endowments, economics and environment in conventional and unconventional gas reservoirs

This paper presents a methodology for connecting endowments, economics and the environment in conventional, tight, shale and Coalbed Methane (CBM) reservoirs. The volumetric estimates are generated by a Variable Shape Distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations. Results indicate a total gas endowment of 70,000tcf, split between 15,000tcf in conventional reservoirs, 15,000tcf in tight gas, 30,000tcf in shale gas and 10,000tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035.A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply curves are estimated in this paper for the global gas portfolio. The curves show that, in some cases, the costs of producing gas from unconventional reservoirs are comparable to those of conventional gas.The conclusion is that there is enough natural gas to supply the energy market for nearly 400years at current rates of consumption and 110years with a growth rate in production of 2% per year. With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels.

Research on the Natural Gas Enrichment Regularity of Es1 Layer in Yangxin Subsag of Jiyang Depression

Natural gas resource of Es1 layer in Yangxin subsag is very abundant. Natural gas formation, enrichment conditions and regularity are analyzed in this paper. Geochemistry analysis shows that natural gas resource of Es1 layer in Yangxin subsag belongs to biological origin gas. The sedimentary environment, ground temperature, gas source rock and preservation condition of the study area is advantageous, which provide a guarantee for natural gas generation and preservation. Research shows that natural gas enrichment in the lower part of Es1 layer because of limestone reservoir development, and on the horizontal direction natural gas is mainly enrichment in the eastern nose structure zone and southern slope zone. The both zones are the preferred zone for natural gas exploration in the study area.

Unconventional oil and gas resource development – Let’s do it right

The resource triangle can be used to describe the distribution of natural gas resources in all basins in the world. We have studied 25 basins in North America and conclude that over 90% of the technically recoverable resources (TRR) in natural gas formations can be found in unconventional reservoirs. We believe these statistics can be extrapolated to every basin in the world that produces substantial volumes of oil and gas. In fact, we have estimated that the world has over 57,000 Tcf of TRR in these basins. Not all of the TRR is economically recoverable because of gas prices, costs and other issues, such as lack of infrastructure, but the gas is there and can be produced in the future. However, the oil and gas industry must follow basic guidelines to ensure safety and environmental awareness as it develops these resources over the coming decades.

Natural Gas Prices on Three Continents

We investigate the pricing formation of natural gas markets on three different continents (Europe, Asia and North America). We find that natural gas markets showed a strong relationship with the crude oil market between 1992 and 2001 and natural gas prices tended to thermal parity with crude oil prices. From 2002 natural gas markets exhibited a less pronounced relationship with the crude oil market and major natural gas markets were severely underpriced compared to crude oil. A globally integrated natural gas market, comparable to the global oil market, has not evolved. The main natural gas markets, however, exhibit some level of integration, especially over a longer time. The European market exhibits the strongest levels of integration, while the North American market exhibits the weakest.

A critical assessment of the efficacy of biocides used during the hydraulic fracturing process in shale natural gas wells

We examined the efficacy of multiple biocides that are commonly used to control sulfate-reducing bacteria in fracturing fluids in shale natural gas formations. Seven biocides (tetrakis [hydroxymethyl] phosphonium sulfate, sodium hypochlorite, didecyldimethylammonium chloride, tri-n-butyl tetradecyl phosphonium chloride, glutaraldehyde, a glutaraldehyde and alkyldimethylbenzylammonium chloride blend, and a glutaraldehyde alkyldimethylethylbenzylammonium chloride blend) were examined. Minimum inhibitory concentrations (MIC) were determined using planktonic cells and biofilms of Desulfovibrio desulfuricans strain G20 and a sulfate-reducing enrichment culture that was obtained from a Barnett Shale frac pond. All biocides had higher MIC values for biofilms compared to planktonic cells from these two cultures. Higher concentrations of all biocides, except didecyldimethylammonium chloride, were required to kill planktonic cells of G20 that were exposed to humic acid. These results clearly indicate that biofilm formation by sulfate-reducing bacteria, as well as organic loading rates, negatively impact the efficacy of biocides. This work provides valuable information concerning the effects of biofilm formation and organic loading on biocide MIC values. These MIC data can be used as a guide for the control of microbial growth in future frac jobs, which should result in fewer incidences of sulfide production and corrosion in shale natural gas wells.

Single carbon surface reactions of 1-octadecene and 2,3,6-trimethylphenol on activated carbon: Implications for methane formation in sediments

The reactions of a terminal alkene (1-octadecene) and a polymethyl phenol (2,3,6-trimethylphenol) on activated carbon have been investigated in closed system pyrolysis experiments in the temperature range 170–340 °C. The reaction products of 1-octadecene included methane, isomeric octadecenes, methyl substituted alkanes, alkyl aromatics and an homologous series of n-alkanes with carbon numbers indicative of progressive single carbon depletion of the reactant. The reaction products of 2,3,6-trimethylphenol also contained methane, as well as C 1–C 4 methyl phenols produced by demethylation and methyl transfer reactions. A carbon surface reaction involving the formation of a reactive single carbon intermediate (i.e. methylene/carbene) is proposed. This reaction accounts for the products observed from the pyrolysis experiments and also is consistent with liquid hydrocarbon distributions found in petroleum basins. Methane was the dominant (ca. 85% of C 1–C 4) gaseous hydrocarbon product of 2,3,6-trimethylphenol but accounted for only ca. 17% of the C 1–C 4 hydrocarbons from 1-octadecene. These findings suggest that single carbon surface reactions may play an important role in the geochemical formation of crude oil and natural gas and that the composition of the source material and therefore the type of organic compounds undergoing such reactions, influences the hydrocarbon gas composition in sedimentary basins.

Origin and stability of a permafrost methane hydrate occurrence in the Canadian Shield

Relatively little attention has been given to the stability of methane hydrates, formed during periods of past climate change, currently in areas of continuous permafrost. Although a large portion of the Canadian arctic is underlain by crystalline rocks, the occurrence, phase, and origin of alkanes in crystalline rocks under thick permafrost conditions (> 500 m) have not been reported. For the first time, composition and isotopic data for gases from a crystalline shield environment currently under permafrost conditions are presented. Gas and water samples were collected from exploration boreholes and seeps between 890 and 1130 m depths in the Lupin gold mine, Nunavut, Canada. Gases were methane-dominate (64–87%), with nitrogen (10–37%) the next largest component, and smaller amounts of ethane, propane, and carbon dioxide. Pressure and temperature measurements indicated gas hydrates were stable at the site prior to mining operations, a conclusion supported by noble gas and salinity determinations. Gas hydrate stability over the last 120 kyr glacial cycle was demonstrated by calculating transient subsurface pressure and temperature conditions utilizing the Memorial University/University of Toronto Glacial Systems Model (MUN/UofT GSM) and the Hydrogeosphere groundwater flow model. Model results also indicated glacial loading increased subsurface pressures, resulting in increased hydrate stability fields during glacial periods. Subglacial groundwater recharge would be limited by any significant formation of gas hydrates. Gas composition, combined with carbon and hydrogen isotopic determinations on methane (− 56 to − 42‰ VPDB and − 349 to − 181‰ VSMOW), carbon dioxide (− 55 to − 15‰ VPDB), ethane (− 37 to − 27‰ VPDB and − 330 to − 228‰ VSMOW), and propane (− 34 to − 27‰ VPDB and − 196 to − 172‰ VSMOW), indicated formation of natural gases by thermogenic processes, mixed with bacteriogenic gas, reasonable, given site geologic history. Methane hydrate formation affected gas composition and gas δ 2H values, complicating the interpretation. Gas production is not a modern process at this location, and the overall contribution to the global carbon budget is small. Glacial groundwater recharge models need to account for methane hydrate formation and dissipation due to changes in subsurface stability fields during glaciation and the effect of methane hydrate on hydraulic conductivity.

Low-mature gases and their resource potentiality

In the 80’s of last century, based on the advances in natural gas exploration practice, the concepts of bio-thermocatalytic transitional-zone gas and early thermogenetic gas were proposed, and the lower limit Ro values for the formation and accumulation of thermogenetic natural gases of industrial importance have been extended to 0.3%–0.4%. In accordance with the two-stage model established on the basis of carbon isotope fractionation involved in the formation of coal-type natural gases, the upper limit Ro values of lowly evolved natural gases should be set at 0.8%–1.0%. This is the concept of low-mature gas which is commonly accepted at the present time. The Urengoy super-large gas field in western Siberian Basin is a typical example of low-mature gas field, where low-mature gas reserves account for 20% of the globally proven natural gas reserves, and this fully indicates the importance of this kind of resources. The proven reserves of natural gases in the Turpan-Hami Basin of China are approximate to 1000×108 m3, and the thermal evolution indices of source rocks are Ro=0.4%–0.8%. The δ13C1 values of methane are mainly within the range of −44‰–39‰ (corresponding to Ro=0.6%–0.8%), and those of ethane are mainly within the range of −29‰–26‰, indicating that these natural gases should be designated to the coal-type low-mature gases. The light hydrocarbon evolution indices of natural gases also provide strong evidence suggesting that they are the coal-type low-mature gases. If so, low-mature gas in the Turpan-Hami Basin has been accumulated to such an extent as to be equivalent to the total reserves of three large-sized gas fields, and their existence is of great significance in the study and exploration of China’s low-mature gases. If it is evidenced that the source rocks of low-mature gases are related mainly to coal measures, China’s abundant lowly evolved coal series resources will provide a huge resource potentiality for the generation of low-mature gases.

The modeling of carbon isotope kinetics and its application to the evaluation of natural gas

The modeling of carbon isotope kinetics of natural gas is an issue driving pioneering research in the oil and gas geochemistry in China and internationally. Combined with the sedimentary burial history and basin geothermal history, the modeling of carbon isotope kinetics provides a new and effective means for the determination of the origin and accumulation history of natural gas pools. In this paper, we introduce themodeling of carbon isotope kinetics of natural gas formation and its applications to the assessment of natural gas maturity, the determination of the gas source, the history of gas accumulation, and the oil-gas ratio. It is shown that this approach is of great value for these applications. The carbon isotopic characteristics of natural gas are not only affected by the gas source and maturity of the source rock, but also are related to the accumulation condition and geothermal gradient in a basin. There are obvious differences in the characteristics of carbon isotope ratios between instantaneous gas and cumulative gas. Different basins have different kinetic models of carbon isotope fractionation, which depends on the gas source condition, the accumulation history and the sedimentary-tectonic history. Since the origin of natural gas in the superimposed basin in China is very complicated, and the natural gas pool is characterized by multiphase and variable gas-sources, this paper may provide a new perspective on the study and evaluation of natural gas.

Low-mature gases and typical low-mature gas fields in China

No natural gas pool of industrial importance could be formed at the low-evolution stage of organic matter. In the 1980s, on the basis of the development in exploration practice, the hypotheses of bio-thermo-catalytic transitional zone gases and early thermogenic gases were proposed. The lower-limit Ro values for the formation and accumulation of natural gases of industrial importance have been expanded to 0.3%–0.4%. In the light of the two-stage model established on the basis of carbon isotope fractionation in coal-type natural gases, the upper-limit Ro values have been set at 0.8%–1.0%. In terms of the geological practice in the low-mature gas zones and China’s main coal-type gas fields, it is feasible and proper to set the upper-limit Ro value of low-mature gases at 0.8%. Supper-large gas fields such as the Urengoy gas field in western Siberian Basin should belong to low-mature gas fields, of which the natural gas reserves account for more than 20% of the global proven reserves, providing strong evidence for the significance of such a type of resources. The proven natural gas reserves in the Turpan-Hami Basin of China have almost reached 1000 ×108 m3. The main source rocks in this area are the Jurassic Xishanyao Formation, which occurs as a suite of coal series strata. The corresponding thermal evolution indices (Ro) are mainly within the range of about 0.4%–0.8%, the δ13C1 values of methane vary between −44‰ and −39‰ (correspondingly Ro =0.6%–0.8%), and those of ethane are within the range of −29‰–−26‰, indicating that natural gases in the Turpan-Hami Basin should be designated to coal-type low-mature gases. The light hydrocarbon evolution indices of natural gases also fall within the area of low evolution while the precursor type of light hydrocarbons also shows the characteristics of the coal-type. The geological background, carbon isotopic composition and light hydrocarbon index all provide strong evidence suggesting that the proven natural gases in the Turpan-Hami Basin are low-mature gases. In China a gas field with the gas reserves reaching 300 ×108 m3 can be defined as a large gas field, and thus the proven low-mature gases in the Turpan-Hami Basin are equivalent to the reserves of three large gas fields. Its existence is of great significance in research on and exploration of low-mature gases in China.

Natural gas formation in the western Nile delta (Eastern Mediterranean): Thermogenic versus microbial

The offshore part of the Nile delta is an emerging gas and condensate province and one of the most promising areas for future petroleum exploration and supply in northern Africa. While the Nile delta’s hydrocarbon potential and its geological and stratigraphic pattern has been the focus of numerous studies, the origin of its gas has been poorly studied. In order to characterize the natural gas and to determine whether microbial or thermogenic processes are the dominant generation pathways of methane, a regional geochemical study was performed on 38 test gases collected from 9 Neogene western Nile delta discoveries. Main constituents of the gases are methane (89.4–99.4%) up to pentane with traces of carbon dioxide and nitrogen. Methane carbon isotopic composition ranges from −66.0‰ to −39.6‰ displaying a mixed microbial and thermogenic character for most of the gases. Microbial gas contributions range from 15% to 95%. The mixed and the more thermogenic gases are frequently accompanied by light oils and condensates (41–59 °API). Calculated maturities of the thermogenic gas proportions suggest source rock maturities between 0.8% and 1.4% Ro, which are actually present in the pre-Miocene section. Evidence for microbial alteration of petroleum accumulations in the Nile delta is largely manifested in anomalously heavy isotopic compositions of both wet-gas components propane and n-butane and preferential removal of higher n-alkanes from condensates. The hydrocarbon accumulations affected by biodegradation are trapped within shallow Pliocene reservoirs (<2400 m) where present day temperatures are below 80 °C. The coexistence of biodegraded thermogenic gas and condensate with dry microbial gas supports the concept that generation of secondary microbial methane by biodegradation of thermogenic hydrocarbons may occur within the Nile delta.

A Prediction on the Performance and Economic Viability of Future Gas Wells in the Western Canadian Sedimentary Basin

Abstract The Western Canadian Sedimentary Basin (WCSB) is dominantly a gas-bearing basin, particularly in the western and northern regions. With the major fluctuations in gas prices over the past year, it has become increasingly difficult to determine the economic viability of exploring for and developing natural gas reserves within the basin. Each geographic area within the WCSB has its own economic criteria from the relatively inexpensive low reserve, low deliverability shallow gas of southeastern Alberta to the high reserve, high deliverability of Western Alberta and Northeastern British Columbia. To compare which plays are economically more attractive, a detailed analysis must be done to statistically compare the risk factors, the ultimate reserves and deliverability for each gas-bearing horizon. In addition, a full cycle economic model must be constructed in order to determine the future economic viability of each play. To predict how future wells will perform, the statistical database must be based on the most recent drilling; however, success, reserves, and deliverability trends through time must also be investigated. The current model subdivides the WCSB into 16 geographic areas and related gas-bearing horizons. Statistical success rates, ultimate reserves, and deliverabilities for current gas wells have been determined for each gas-bearing interval through time. Data from the last five years is then utilized to predict the risked and unrisked reserve and deliverability distribution for future wells within each geographic area. An economic model using land, seismic, capital, and operating costs compares gas plays, prospects, and acquisition opportunities across the WCSB. During the period January 1999 to December 2004, 44,224 gas wells (that can be declined) have been put on production. These wells have found in excess of 17.2 TCF of gas reserves with an average reserve per well of 0.39 BCF. The geographic area where the most gas wells were drilled and put on production was in Southern Alberta with 20,344 wells. Southern Alberta also showed the lowest average reserves per well, of wells that can be currently declined, of 0.11 BCF while the BC Foothills showed the highest reserves per well of 7.8 BCF. Introduction The full cycle economic viability for all productive natural gas formations ("gas plays") in the Western Canadian Sedimentary Basin ("WCSB") can be determined using publicly available geological, land, and production data. This paper represents a summary of the processes utilized in a series of larger regional studies performed by the consulting firm AJM Petroleum Consultants (AJM) from 2001 to the present. The regional studies utilized various parameters for the gas plays resulting from an unbiased statistical analysis of all wells drilled during the most recent five-year period within the WCSB. Results were reported for both risked (Exploration and Development) and unrisked (Development) cases. The area investigated in the regional studies includes all productive natural gas formations in Western Saskatchewan, Alberta, and Northeastern British Columbia. The basin was subdivided into 16 geographic areas (Figure 1).

The generation and accumulation of natural gas from Yinan 2 gas pool in Kuqa Depression

By using the methods of hydrocarbon generation kinetics and carbon isotope kinetics, combined with geological background of natural gas pool formation, the generation and accumulation of natural gas from Yinan 2 gas pool was studied in Kuqa Depression of the Tarim Basin. Natural gas of Yinan 2 gas pool is mainly derived from Middle and Lower Jurassic coal-bearing source rocks, and generally belongs to long time-accumulated gas. It is suggested that Yinan 2 gas is chiefly accumulated in the last 5 Ma, itsR 0 ranges from 1.25% to 1.95%, and the loss rate of natural gas is about 25%–30%. This work not only complements and reduces the deficiency of formation model of natural gas pools which traditionally depends on the matching relationships between source rock, reservoir, cap rock, and trap, but also is a useful reference in the study of other gas pools.