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Research on predicting the growth trend of natural gas reserves and production will help provide a scientific basis for natural gas exploration and development. The metabolically improved modified weight coefficient GM(1,n) method is applied to the multi-cycle Hubbert model to predict the trend of new proven natural gas reserves in the Sichuan Basin. The ultimate recoverable reserves (URR) is introduced as a boundary condition in the production-time series to predict the natural gas production growth. The research results show that: (1) The annual newly added proven natural gas reserves of the Sichuan Basin maintain a multi-cycle growth trend, which will reach the peak reserves in 2034, at which time the proven rate of natural gas will reach 36%. (2) Based on the predicted results of proven reserves, the final recoverable reserves of natural gas are estimated to be $$5.25-5.75\times {10}^{12}{m}^{3}$$ 5.25 - 5.75 × 10 12 m 3 . The production in 2035 will reach $$750-810\times {10}^{8}{\mathrm{m}}^{3}/\mathrm{a}$$ 750 - 810 × 10 8 m 3 / a , and production will grow rapidly. The exploration and development of natural gas in the basin will be prospective for a long time.

Surface geophysical measurements of resistivity, magnetic and gravity were evaluated in combination along same traverses to detect and quantify ore reserves in order to enable the design of effective and sustainable mining strategy for some remote barite fields in the Abakaliki basin, southeastern Nigeria. In addition to the surface geophysical measurements, geological field mapping of ores bodies and host rocks were undertaken to calibrate geophysical models. Numerical modeling and geological interpretation of the geophysical data indicate and delineate zones of ore occurrences and provide ore tonnage estimates for the studied fields. However, tonnage estimates in some regions were severely flawed as demonstrated by some consequent futile surface excavations. The failure recorded by the open excavated pits is linked to the pitfalls in some ore quantity estimates that bear largely on survey layout design and significant errors emanating from data interpretation due to complex structural and stratigraphic setting of ore incidence, all of which contributed to constrain the reliability on the geophysical data alone as a mine design tool. Best practice necessitates that excavation designs are to be preceded by exploratory drilling to ascertain proven reserves.

The North Peixian mining area of China has rich coal resources, with total proven reserves of 2.37 billion tons. However, the underground coal mining activities have resulted in ground collapse, which has caused serious harm to the environment and threatened the lives and properties of local residents. In this study, 12 Sentinel-1A terrain observation by progressive scans (TOPS) mode acquisitions between 30 July 2015 and 13 May 2016 over the abandoned mining area in North Peixian were analyzed using the interferometric synthetic aperture radar (InSAR) time series method to detect the ground subsidence, with the maximum ground subsidence reaching 83 mm/a and an average value of about 12.7 mm/a. The subsidence results derived from the Sentinel-1A TOPS mode dataset were proven to be effective in investigating and monitoring the ground subsidence in the North Peixian mining area. Compared to the rapid deformation during the ongoing period of mining excavation, the ground subsides slowly in abandoned mining areas and shows a linear relationship with time over a relatively long period of time. Spatial correlation between the subsidence distribution and land cover was found, in that the magnitude of the subsidence in urban areas was smaller than that in rural areas, which is associated with the controlled coal mining activities under buildings, railways, and water bodies. The results demonstrate that Sentinel-1A TOPS SAR images can be used to effectively and accurately detect and monitor ground subsidence in a mining area, which is critically important when investigating land subsidence in a large-scale mining area.

Tahe oil field is the first marine origin oil field in China, with proven reserves of 500 million tons. Given the important role of the paleogeomorphology in controlling the formation and distribution of karst reservoirs, this paper restored the pre-Carboniferous paleokarst landform in the major blocks of the Tahe oil field, via the paleogeomorphic genesis assembly method. First, four types of secondary landform units (karst platform, karst gentle slope, karst steep slope, and karst intermountain basin) were defined. Next, landform identification factors were added to these four types, to further divide the paleokarst landform into ten tertiary landform units. This enabled a more precise identification of the paleogeomorphic landforms. The karst development and the properties of hydrocarbon reservoirs in micro-geomorphic units were assessed. In addition, the relationship between petroleum production and geomorphology was analysed to robustly predict karst reservoirs in the Tahe oil field. The results show that karst develops differently according to the ancient landform units it developed from and that the current karst function is highly dependent on the precursor ancient landform. In addition, the morphology of the ancient landform significantly controls hydrocarbon accumulation, with oil and gas production being highly associated with the degree of karst development in each landscape unit. The research results indicate that the position of the slope in the karst hill and residual peak is favorable for future oil and gas exploration.

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.

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.

This paper shows that there is a strict quantitative connection between three factors: reserves-to-production ratio (w), rate of production growth (a), and degree of reserve replenishment during 1 year (i). The first of these factors shows how many years the current level of production can be supported by existing proved reserves (if both are invariable). The second factor shows how quickly the production increases. The third, characterizes the correlation between oil production and reserves discovery, which is the basis for potential oil production growth. For planning purposes it is important to know how many units of new reserves have to be proved during each year per one unit of production for the different reserves-to-production ratio and production growth. The results of calculating these factors are shown in the table and pictured on the graph. They can be used for regions where the replenishment of proven reserves (factor (i)) exceeds 1 barrel of new reserves per 1 barrel of production. This paper also describes the interdependence and dynamics of these factors when the replenishment of proved reserves is incomplete.

The US Department of Energy's Energy Information Administration (EIA) recently predicted that world oil production could continue to increase for more than three decades, based on the recent US Geological Survey (USGS) evaluation of world oil resources and a simple, transparent model. However, it can be shown that this model is not consistent with actual oil production records in many different regions, particularly that of the US, from which it was derived. A more careful application of the EIA model, using the same resource estimates, indicates that at best non-OPEC oil production can increase for less than two decades, and should begin to decline at the latest sometime between 2015 and 2020. OPEC at this point will completely control the world oil market and will need to meet increased demand as well as compensate for declining production of non-OPEC producers. OPEC could control the market even sooner than this, given its larger share of proven oil reserves, probable difficulties in transforming non-OPEC undiscovered reserves into proven reserves, and the converging interests of all oil producers as reserves are depleted. This has significant implications for the world economy and for US national security.

The so-called “large-medium gas field” means a gas field with proven reserves equal to or larger than 100 × 108 m3. Up to 1997, 23 coal-formed great-medium fields are discovered in China, excluding two in Taiwan Province. Their proven reserves take 50.9% in total natural gas reserves. Therefore, the coal-formed great-medium gas field plays a decisive role in natural gas reserves and the study of their controlling factors is very important both in theory and in practice. There are six major controlling factors on the formation of coal-formed large-medium gas fields: (i) The generating center of coal-formed gas and its surrounding area; (ii) low potential area; (iii) late pool-forming period; (iv) traps related to the paleo-uplifits in coal-formed gas area; (v) above or between abnormally pressured compartments; (vi) faulted traps related to coal-bed.

Proven reserves of liquid hydrocarbons are now assessed at between 950 and 1,000 billion barrels, depending on the source. Their life expectancy at the current rate of world production is about 41 to 45 years. This lifetime is much longer than what was predicted in both 1970 and 1980. However, this wealth of resources does not necessarily mean that the security of oil supplies is guaranteed for all countries. Oil reserves are unequally distributed from a geopolitical standpoint. Reserves and output are mainly due to big fields (with more than 500 million barrels of initial reserves). Though oil supplies seem to be ensured for the coming 30 to 40 years, what does the picture look like beyond 2020–20307 The increased lifetime of proven oil reserves has been apparent only in the last 10 to 20 years. The considerable increase in proven oil reserves reported after 1986 is, in fact, mainly due to revisions and extensions, rather than to new sources of oil: conventional oil (with the price per barrel of oil on the order of $20 and recovery rate around 30 percent) remaining to be discovered today; oil resources stemming from an improvement in recovery rate; oil resources resulting from exploitation of new zones, such as deep sea zones; and unconventional types of oil, such as extra-heavy crudes, tar sands, shale oils, and liquid hydrocarbons from chemical-enhanced oil recovery methods.

Oil exploration in Israel began in 1953. Until 1991 a total of 263 exploration wells and 122 development wells were drilled, 3 oil fields and 5 gas fields were discovered, and 4 noncommercial oil discoveries and 1 noncommercial gas discovery were made. Proven in-place reserves amount to 70 million barrels of oil equivalent (MMBOE). Exploration focused on six main plays: Syrian Arc anticlines; Mesozoic platform-edge, structural-stratigraphic traps; the Dead Sea graben; Early Mesozoic structures; Saqiye Group biogenic gas; and Hula Group biogenic gas. The more significant discoveries are associated with the first two plays. Ninety percent of the proven reserves were discovered by the first 71 wildcats, which constitute 27 percent of all wildcats drilled to date. During this phase of exploration, the average success was 7 percent, and the average discovery rate was 0.88 MMBOE per wildcat. Most of the following 192 wildcats were dry holes. If, as experts claim, significant reserves are still undiscovered, previous exploration must be deemed inefficient. The quantitative model of the discovery process also leads to such an assessment.