Deep Natural Gas Research Articles

Exploring the prospects of deep natural gas resources from the geochemical parameters of the Shahejie Formation source rocks in the Banqiao depression

Deep natural gas is an important field and direction for oil and gas exploration and development in the Banqiao depression. The geochemical characteristics of the Paleogene Shahejie Formation source rocks in the Banqiao Sag were investigated based on pyrolysis, Total Organic Carbon (TOC), chloroform bitumen A, vitrinite reflectance, saturated hydrocarbon gas chromatography–mass spectrometry, and maceral determination. The results showed that the Es3 source rocks of the Paleogene Shahejie Formation were generally of better quality than the Es1 source rocks. Regarding the Es1 source rocks, the abundance of organic matter was variable, with mixed types and low maturity. The source rocks were formed in a saline-water reductive environment. Regarding the Es3 source rocks, the abundance of organic matter was relatively high, meaning that they were of medium–high quality, with mixed types of, yet highly mature, organic matter. The hydrocarbon generation environment was oxidative, and the source rocks were mainly deposited in fresh water with localized salinization. The main hydrocarbon-generating components of organic matter in the Shahejie Formation were amorphous humic components formed by intensive microbial modification of lower planktonic algae and terrestrial higher plants. Aquatic organisms were the main sources of organic matter, with localized mixing of higher-plant organic matter. The organic matter derived from these higher plant debris sources provided beneficial conditions for the generation of natural gas. At present, the Shasan source rock is at the peak of hydrocarbon generation. Under deep conditions, the maturity of organic matter increases, and organic matter rich in terrestrial higher plants can make a significant contribution to the generation of natural gas, especially shale gas.

The generation mechanism of deep natural gas in Tabei uplift, Tarim Basin, Northwest China: insights from instantaneous and accumulative effects

The natural gas heavy carbon isotope and high dryness coefficients genesis in Tabei uplift, Tarim Basin has been highly controversial. To investigate the generation mechanisms of natural gas in the Tabei Uplift. Natural gas chemical composition, carbon isotopes were used to analyze the genesis of natural gas, source rock maturity, and basin modeling were conducted to reconstruct the natural gas generation process, and the influences of instantaneous and cumulative effects on natural gas properties was discussed. The results show that the dryness coefficients of natural gas range from 0.62 to 0.99 (average: 0.92), the methane contents range from 30.42% to 96.4% (average: 85.10%), ethane contents from 0.43% to 15.58% (average: 3.39%), propane contents from 0.11% to 11.43% (average: 1.78%), and the methane carbon isotopes range from −47.30‰ to −33.80‰ (average: −36.96‰), ethane carbon isotopes range from −39.60‰ to −33.20‰ (average: −35.57‰), propane carbon isotopes range from −36.90‰ to −28.50‰ (average: −35.49‰). Compared with the actual regional thermal evolution of the source rock (Ro% range from 1.4%∼1.7%), the natural gas exhibits excessively high dryness coefficients and heavy methane carbon isotope characteristics. The natural gas is primary cracking gas and sourced from marine type II kerogen. The dryness coefficient, methane carbon isotopes, and source rock maturity gradually increases from the west to the east. Instantaneous effects and leakage led to the dry gas and relative heavy methane carbon isotopes generated at a low maturity level. The current natural gas in the Ordovician reservoirs was all generated during the Himalayan orogeny. Long period pause of the gas generation between the two hydrocarbon generation phases is the main cause for the instantaneous effects.

Geochemical Characteristics of the Paleozoic Marine Source Rocks and Ultra-Deep Hydrocarbon Accumulation Mode of the Awati Sag

The Lower Paleozoic of the Awati Sag and its periphery is a region with relatively low levels of exploration and stands as a frontier for ultra-deep hydrocarbon exploration. Based on outcrop and core samples, this study integrated organic geochemical analysis, total organic carbon (TOC) logging interpretation, and one-dimensional and two-dimensional hydrocarbon accumulation simulations, to clarify the primary source rock of the Lower Paleozoic and its characteristics, as well as its hydrocarbon accumulation mode. The findings indicate the following: (1) The Lower Paleozoic features two sets of industrial source rocks. The Yuertusi Formation, with its considerable thickness (approximately 200 m), widespread distribution, and elevated TOC (averaging approximately 5% from experimental data and logging interpretation), stands out as the Lower Paleozoic’s most pivotal source rock. (2) The Yuertusi and Saergan Formations are in a high-to-over-mature stage, with the Yuertusi initiating oil generation in the early Silurian and transitioning to gas by the late Permian. The Saergan began producing oil in the Carboniferous, followed by gas in the late Permian. (3) The potential ultra-deep gas reservoirs in the Awati Sag are mainly distributed in the structural traps closer to the deep faults in five potential target formations. Deep natural gas typically exhibits mixed-source signatures, with the mixing notably pronounced along the Shajingzi Fault Belt due to influential basin-controlling faults.

Extreme organic matter enrichment in the Ediacaran Doushantuo formation: New constraints from the NE Sichuan basin, China

The Yangtze Block is a highly prospective area for Ediacaran natural gas exploration in recent years, especially the Doushantuo Formation, a vital source rock for organic-rich hydrocarbon and a shale gas reservoir in the region. However, understanding of the Ediacaran organic-rich source rocks systematically has been limited due to the heterogeneous accumulation of organic matter and confusing paleoclimatological and paleoceanographic conditions. Such a scenario is not conducive to further exploration of the deep Ediacaran natural gas resources or understanding the evolution of early Earth. In this study, based on two new well drillings in the northeastern Sichuan Basin, the integrated sedimentological and geochemical investigations were focused on the Ediacaran middle−upper Doushantuo Formation (DST) fine-grained rocks interval. Results show this set of black organic-rich shales (total organic carbon up to 13.97%) deposited under episodic warming climate during an otherwise protracted cooling trend. These frequent climatic fluctuations intensified hydrological circulation, which together with the concurrent hydrothermal activity and the Neoproterozoic Oxidation Event, led to eutrophication of surface seawater. Under these circumstances, a substantial enhancement in primary productivity driven by algae blooming, subsequently resulted in consume excess dissolved oxygen in seawater during the degradation stage and anoxic-euxinic bottom water expansion. Consequently, the high paleoproductivity controlled the extreme organic matter enrichment during the Doushantuo time and formed the DST 4 organic-rich shales in the Chengkou and Nanhua subbasins. In contrast, although the DST 3 shales still deposited under a high productivity condition, the shallower sedimentary environments with anoxic-oxic bottom water conditions resulted in greater variation in total organic carbon contents.

Investigation on coupling deposition and plugging of hydrate and wax in gas–liquid annular flow: Experiments and mechanism

The coupling deposition and plugging caused by hydrate formation and wax precipitation during the development of deep water natural gas resources bring new industrial challenges and theoretical difficulty. We designed a single-pass pipeline with two types to investigate deposition behavior and systematically performed the coupling deposition and plugging of hydrate and wax experiments in gas–liquid annular flow. The experimental results illustrate that the single solid phase of hydrate is covered layer sheet deposition, while the coupling solid phase of hydrate and wax is bulk aggregations arch bridge deposition. Meanwhile, the natural eddy zone in reducing pipeline accelerates coupling solid particles deposition. Our finds provided the first knowledge on the double effect that wax crystals inhibit particles adhesion and gel network increases aggregations arch bridge blockage. For the low water content in emulsion system, the gel network provides gathering place for hydrate particles, and the arch bridge structure formed by aggregations accelerates the pipeline blockage. The plugging time is shortened by up to 72.6% with the wax concentration increase from 0 wt% to 3 wt%. For the high water content in emulsion system, the majority of wax crystals adsorbed on the hydrate particles and reduce particles cohesion force, which increase the plugging time. Combined with the microscopic morphology evolution perspective of hydrate particles coupled wax, the coupling deposition of hydrate and wax in gas–liquid annular flow has four stages: gas–liquid flow, coupling solid phase formation, coupling solid phase deposition and sloughing, and coupling solid phase plugging. This study can provide theoretical support and design basis for flow assurance program of deep water gas fields and low temperature natural gas transportation pipelines.

Effects of differential tectonic activities on overpressure evolution in the deep-water area of the Qiongdongnan Basin: implications for gas hydrate accumulation

The lack of data on the complex tectonics of the Qiongdongnan Basin has thus far restricted our understanding of the overpressure, deep hydrocarbon and shallow gas hydrate distribution. We therefore combined integrated seismic, well and borehole test data with basin models to clarify the relationship between tectonic activity and overpressure evolution, as well as the potential effects of the subsurface pressure on gas hydrate accumulation. The results show differences in tectonic activity and pressure characteristics between the eastern and western basins. Large numbers of faults and magmatic intrusions have developed in the post-rift layer of the eastern basin (the Baodao to Changchang sub-basins) since the Late Miocene ( c. 10.5 Ma), although they seldom formed in the western basin (the Lengdong to Lingshui sub-basins). Correspondingly, the eastern basin was characterized by lower overpressures (up to 40 MPa) and the western basin displayed higher overpressures (up to 110 MPa). The results indicate that tectonic activity since c. 10.5 Ma caused the relief of overpressure in the eastern basin. In stark contrast, the overpressure in the western basin increased significantly due to the lack of structural conduits and rapid sedimentation of the thick Pliocene and Quaternary deposits. Numerical models reveal that the faults and gas chimneys associated with the intrusions constituted shallow plumbing systems through which deep natural gas was able to migrate upwards. The formation of gas hydrates relied on the migration of deep gas to the hydrate stability zone below the seafloor. The relatively lower overpressured zones due to pressure relief in the eastern basin are therefore considered the next areas potentially favourable for the formation of gas hydrates. Thematic collection: This article is part of the Emerging knowledge on the tectonics of the South China Sea collection available at: https://www.lyellcollection.org/topic/collections/south-china-sea

Characterization and Analysis of Corrosion Resistance of Rubber Materials for Downhole Tools in a High-Stress Environment with Coupled H2S-CO2.

In the process of constructing deep natural gas wells in Sichuan and Chongqing, gas wells encounter various technical challenges such as high temperature, high pressure, and a corrosive environment containing H2S and CO2. The corrosion of rubber materials in these acidic environments can easily lead to seal failure in downhole tools. To better investigate the corrosion resistance of rubber materials in acidic environments, we utilized a dynamic cyclic corrosion experimental device capable of simulating the service conditions experienced by downhole tools under high-temperature, high-pressure multiphase flow. Corrosion-resistance tests were conducted on fluororubbers (FKM) 1, 2, 3, and HNBR (hydrogenated nitrile-butadiene rubber) under acidic conditions (80 °C and 160 °C), along with sealing corrosion tests on O-rings. These tests aimed to analyze the mechanical properties, hardness, and corrosion resistance before and after exposure to acid media as well as the sealing performance of O-rings. Ultimately, our goal was to identify suitable rubber materials for acidic pressure environments. Experimental results revealed that all four types of rubber exhibited decreased elongation at break after undergoing corrosion testing; however, fluororubber 3 demonstrated significant susceptibility to temperature effects while the other three types showed minimal impact from temperature variations. Fluororubber 1 and fluororubber 3 displayed substantial deformation levels whereas mechanical properties greatly deteriorated for fluororubber 2. Overall, HNBR showcased superior comprehensive performance.

Geochemical characteristics and genesis of the Ordovician sub-salt natural gas in the Ordos Basin, China

A significant amount of natural gas resources has been discovered in the Ordovician reservoirs under a thick layer of gypsum-salt strata as a result of ongoing research into deep natural gas in China’s Ordos Basin, however, the genetic type and source of the Ordovician sub-salt natural gas remain contentious. These limits understanding how the geochemical properties of the natural gas in Ordos Basin have evolved and how to best guide future exploration and development. Based on the components, carbon and hydrogen isotopic ratios of natural gas from the latest exploration wells, combined with the geological background, this study systematically analyzed the genetic types and sources of sub-salt natural gas of the central and eastern Ordos Basin. The results show that the Ordovician natural gas is mainly composed of hydrocarbon gases with low content of heavy hydrocarbons and dryness (CCH4/CCH4+) above 0.95, belonging to typical dry gas. Non-hydrocarbon gases mainly include N2 and CO2, and some natural gas samples contained H2S. The Ordovician sub-salt natural gas is primarily a self-generating and self-preserving oil-cracking gas with relatively high maturity (Ro ranging from 1.5% to 2.1%) mixed with coal-derived gas generated from upper-Paleozoic coal with relatively low maturity (Ro ranging from 1.1% to 1.5%). Due to the dual-source hydrocarbon supply, the Ordovician sub-salt reservoirs provide favorable gas accumulation conditions and development prospects. This study offers a reasonable explanation for the anomalous geochemical characteristics of the Ordovician sub-salt reservoirs in the Ordos Basin, and also may serve as a guide for future exploration of natural gas in the carbonate gypsum-salt sedimentary system in other basins.

Dynamic evolution of gas hydrate systems affected by magmatism and Quaternary mass-transport deposits in the Qiongdongnan Basin, South China Sea, and implications for the global carbon cycle

Methane release from hydrate systems has long been considered as one of the important mechanisms for global carbon cycle perturbations and ocean acidification. Here, a Quaternary active gas hydrate system in Qiongdongnan Basin, South China Sea (SCS), has been analyzed by using seismic, logging while drilling (LWD), and core data. The results show that post-rift magmatism led to the reactivation of a magma diapir, and the faults and fractures related to its emplacement created efficient pathways for deep gas migration. The increase in overburden temperature and circulation of deep thermal fluids, especially in the center of the diapir area, thinned the gas hydrate stability zone (GHSZ). The accumulation of natural gas at the base of GHSZ and the thinning of GHSZ decreased the ability of hydrate bearing sediments to seal free gas and lead to hydraulic fracturing. The free gas entering the GHSZ was buried by mass transport deposits (MTDs) and then formed hydrates due to the overlying compaction and so further sealed the free gas under the GHSZ. This study indicates that two contrasting mechanisms are acting: (1) tectonic activity and magmatism favor the release of deep natural gas which may reach the ocean, (2) MTDs and the overlying compacted sections act as seals, inhibiting the release of such gas to the ocean. This study shows how the seal capacity of MTDs may reduce methane release from deep-seated reservoirs into the ocean. Given their widespread distribution along continental margins, we suggest that the impact of MTDs on vertical fluid flow, and potential consequences for ocean chemistry and the global carbon cycle, might be underestimated.

Deciphering the origin and secondary alteration of deep natural gas in the Tarim basin through paired methane clumped isotopes

The Tarim Basin is one of the most complex, ancient, and petroliferous deep craton basins in the world. Multiple sets of source rocks, stages of tectonism, and episodes of hydrocarbon generation and accumulation complicate the formation and evolutionary processes of hydrocarbons in the basin, especially for the deeply buried petroleum system at >6000 m depth. Paired clumped isotopes (Δ13CH3D and Δ12CH2D2) allow the investigation of methane isotopic bond ordering, elucidating the methane generation mechanism and its post-generation processes, which can complement studies of the molecular and conventional stable isotopic compositions of gas hydrocarbons in constraining the origin and source of natural gas. This study focused on methane clumped isotopes, and chemical and conventional stable isotopic compositions of natural gas samples from four typical oil and gas regions of the Tarim Basin. Results indicate that these gases are thermogenic gases with relatively high stable isotopic δ values (i.e., −46.1‰ < δ13C–CH4 < −25.9‰, −184‰ < δD-CH4 < −140‰). Most exhibit equilibrium methane clumped isotope signatures at temperatures of 128–257 °C, consistent with the main oil-window to gas-window region. The clumped isotope apparent temperature of equilibrated methane was used to determine its formation temperature, which was applied for gas–source correlations and thermal maturity assessments of the natural gases based on the results of previous basin modeling. The clumped isotope compositions of two gas samples from the Keshen area of the basin are characterized by significant deficits in Δ12CH2D2 values but with similar Δ13CH3D values to those of other equilibrated gases there, indicating the possibility of methane bond re-ordering at high temperatures (>300 °C) exceeding the methane “closure temperature”. Non-equilibrium gases in the Tabei area yielded a plausible Δ13CH3D apparent temperature (<160 °C) with a pronounced deficit in Δ12CH2D2 values, possibly owing to irreversible chemical kinetic processes in thermal cracking of organic matter at early thermal maturity (Ro < 1.5‰) or mixing between thermogenic gases generated at two distinct temperatures (i.e., ∼200 °C and ∼120 °C). Equilibrium clumped isotope signatures also rule out the possible effects of secondary alteration on natural gases in the Hetianhe area that were previously considered in conventional isotope studies. Such findings demonstrate that methane clumped isotopes provide independent and effective indicators of gas–source correlations in deep basins while also elucidating secondary processes that are often under- or over-estimated in conventional stable isotope studies.

Lower Cretaceous volcanic-sedimentary successions of the continental rift basin in the Songliao Basin, northeast China: Implication in high-quality reservoir prediction and hydrocarbon potential

The high-quality reservoirs of volcanic-sedimentary successions in faulted lake basins are important enrichment sites for deep natural gas reservoirs. However, complex volcanic-sedimentary lithology and reservoir characteristics impede the efficient prediction of hydrocarbon in these successions. Therefore, we study the volcanic-sedimentary succession of the Huoshiling Formation (northern Dehui depression, Songliao Basin), focusing on the volcanic-sedimentary stratigraphic cycle (VSC), facies models and the distribution of high-quality reservoirs. Based on the log, core, casting thin-section, seismic and other data, fissure-type and central-type volcanic eruptions are identified. Three VSCs (1–3) are recognised, and six volcanic-sedimentary facies are determined based on lithological characteristics: effusive, explosive, volcanic conduit, volcanic-sedimentary transition, fan-delta and lacustrine. Based on the flow regimes and lithological associations, we develop three models: a fissure-central volcanic effusive model, an intermittent volcanic activity model and a fissure-central explosive model. Three types of pores occur in the volcanic-sedimentary reservoir space: primary pores, dissolution pores and micro-fractures. Lithology and dissolution are critical factors controlling reservoir porosity and connectivity. The distribution of high-quality reservoirs of volcanic-sedimentary successions can be effectively predicted using geostatistical seismic-inversion based on porosity constraints. High-quality reservoir characteristics, source rock and structural characteristics show that crystal debris and breccia-bearing tuff in VSC3 can form structural-lithologic, fault-block and self-generating and -storing hydrocarbon reservoirs. This study's results and methods of high-quality volcanic-sedimentary reservoirs can provide a reference for the efficient exploration and development of oil and gas in similar basins.

The Water Problems and Treatment Strategies of Volcanic Gas Reservoir in Daqing

In order to realize the development strategy of “stabilizing oil and increasing gas and simultaneously boosting oil and gas”, Daqing Oilfield has continuously strengthened the exploration and development of deep natural gas resources since the discovery of Xushen gas Field. The volcanic gas reservoir is the main gas producing area of Songliao Basin. Through “internal excavation and external expansion”, natural gas production has maintained a trend of growth for 12 consecutive years. However, due to the development of fractures and bottom water in volcanic gas reservoir, the development contradiction caused by gas well water is increasingly prominent as the gas field development enters the end of stable production stage. Therefore, on the basis of the understanding of four types of effluent water in volcanic rock reservoir, this paper carries out the analysis of the production dynamic characteristics of typical gas wells, and identifies the difficulties faced by gas wells with different types of effluent water. Through field tests, economic and feasible treatment measures are explored, including continuous circulation gas lift of strong water breakthrough gas well in fracture vertical direction, intelligent foam drainage gas production of weak water breakthrough gas well in fracture vertical direction, and deep water unlocking of gas well in pore vertical water cone and gas reservoir with high water saturation gas reservoir effluent water, which provides technical support for the sustainable and efficient development of volcanic gas reservoir.

An FR–IR model method for restoring the original organic geochemical parameters of high over-mature source rocks with types I and II kerogen in China

Deep natural gas source rocks are generally in a stage of high over-maturity. Based on the TOC and hydrocarbon generation potential (HGP) data, the accuracy of present evaluations of deep oil and gas resource potential are greatly reduced. The original TOC and HGP determine the quanlity of hydrocarbon generation from organic matter (OM), therefore, it is particularly important to restore the original organic geochemical parameters. By determining the HI and Tmax of numerous source rocks ranging in maturity levels from immature to over mature, it was found that the HGP characteristics of marine and continental source rocks with the same OM type were similar, providing a prerequisite for the establishment of forward recovery (FR) and inversion recovery (IR) models. Based on the relationship between the TOC and HI of immature to low-maturity source rocks with types I and II kerogen, the original HI was corrected, and the original TOC thresholds for different OM types of source rocks were determined to optimize the FR–IR model. Through the thermal simulation experiments of many samples, the TOC conversion rates from the immature to over mature stages were obtained, and the FR model was formed. The IR model was established based on geochemical data of the organic source rocks of types I, II1 and II2 with different maturity levels. Finally, by considering the typical marine and continental high over-mature source rocks of the world, the restoration results of the FR and IR models were found to have good correlation (average of 0.96) and coincidence rates (average of 72.2%). It was proven that the established FR–IR model have universal applicability in the restoration of the original TOC and HGP of marine and continental high over-mature source rocks with types I and II kerogen, especially in China.

New insight into abiotic or biotic gas in deep reservoirs of the CL-I gas field in Songliao Basin (China) by light hydrocarbons associated with natural gas

Abiotic synthesis through carbon dioxide (CO2) reduction may provide the prebiotic organic compounds needed for the emergence of life, whereas petroleum geologists pay more attention to whether abiotic gas generated by purely chemical reactions plays a prominent role in the formation of industrial gas pools like biotic gas. The Cretaceous reservoir associated with volcanic rocks of the Songliao Basin in northeastern China is suspected of possessing abiotic gas due to some abnormal geochemical characteristics, such as abundant 13C-enriched CO2, 13C-enriched CH4, 13C-depleted C2H6, and an isotopic trend of decreasing 13C content with growing carbon number. To understand further the genesis of deep natural gas, we examined the molecular and isotopic compositions of C1–C4 alkanes, CO2, and light hydrocarbons (LHs) of equal number (four) of gas samples collected from the Yingcheng (K1yc) volcanic and Denglouku (K1d) clastic reservoirs in the Changling (CL-I) gas field. Compared with the products of abiotic polymerization composed of 13C-depleted straight-chain alkanes, various 13C-enriched LH isomers that are highly compatible with the molecular and isotopic compositions of coal-derived thermogenic gas are confirmed in our samples, such as 2-methylhexane (2-MH), 2,3-dimethylpentane (2,3-DMP), cyclohexane (CH), methylcyclohexane (MCH), and other branched-chain alkanes or cycloalkanes. The striking invariable K1 ratio and resemblance of isotopic curves of LHs further indicate that the natural gas in different reservoirs is derived from underlying homologous source rocks, regardless of the variation of CO2 content (K1yc > 15% and K1d < 1%). Combining geological conditions, we propose that C1–C4 and LHs that have no inherent correlation with the concentration of CO2, which is predominantly derived from mantle degassing, are generated from the thermal decomposition of 13C-enriched type III organic matter during burial and diagenesis rather than sourced from mantle degassing, abiotic polymerization, or mixing of thermogenic gas. In addition, we also suggest that the geochemical anomalies consisting of 13C-enriched methane and 13C-depleted ethane are the products of the chemical mechanisms controlled by high temperature, and mantle-derived non-hydrocarbon gas (e.g., CO2 and He) are simply added to thermogenic gas.

Petroleum Geology and Exploration of Deep-Seated Volcanic Condensate Gas Reservoir around the Penyijingxi Sag in the Junggar Basin

Many types of volcanic rock oil and gas reservoirs have been found in China, showing great petroleum exploration potential. Volcanic reservoir also is one of the key fields of exploration in the Junggar Basin and mainly concentrated in the middle and shallow layers, while the deep volcanic rock and natural gas fields have not been broken through. Based on comprehensive analysis of core observation, single well analysis, reservoir description, source rocks evaluation, combined with seismic data and time-frequency electromagnetic technology, multiple volcanic rock exploration targets were identified, and industrial oil and gas flow was obtained in the well SX 16 of the Penyijingxi Sag, western Junggar Basin. It is believed that the deep Permian source rocks have relatively higher natural gas generation potential and volcanic breccia usually have large reservoir space. And the mudstone of the Upper Wuerhe Formation played as the role of caprock. The success of exploration well SX16 has achieved a major breakthrough in natural gas exploration in the Penyijingxi Sag, which has essential guiding significance for the exploration of deep volcanic rocks and large-scale gas exploration in the Junggar Basin.

Analysis of the world oil and gas exploration situation in 2021

The global exploration investment, new oil and gas discoveries, exploration business adjustment strategies of oil companies in 2021, and future favorable exploration domains are systematically analyzed using commercial databases such as IHS and public information of oil companies. It has been found that the world oil and gas exploration situation in 2021 has continued the downturn since the outbreak of COVID-19. The investment and drilling workload decreased slightly, but the success rate of exploration wells, especially deepwater exploration wells, increased significantly, and the newly discovered reserves increased slightly compared with last year. Deep waters of the passive continental margin basins are still the leading sites for discovering conventional large and medium-sized oil and gas fields. The conventional oil and gas exploration in deep formations of onshore petroliferous basins has been keeping a good state, with tight/shale oil and gas discoveries made in Saudi Arabia, Russia, and other countries. While strengthening the exploration and development of local resources, national, international, and independent oil companies have been focusing on major overseas frontiers using their advantages, including risk exploration in deep waters and natural gas. Future favorable exploration directions in the three major frontiers, the global deep waters, deep onshore formations, and unconventional resources, have been clarified. Four suggestions are put forward for the global exploration business of Chinese oil companies: first, a farm in global deepwater frontier basins in advance through bidding at a low cost and adopt the “dual exploration model” after making large-scale discoveries; second, enter new blocks of emerging hot basins in the world through farm-in and other ways, to find large oil and gas fields quickly; third, cooperate with national oil companies of the resource host countries in the form of joint research and actively participate exploration of deep onshore formations of petroliferous basins; fourth, track tight/shale oil and gas cooperation opportunities in a few countries such as Saudi Arabia and Russia, and take advantage of mature domestic theories and technologies to farm in at an appropriate time.

Dynamic reconstruction of the hydrocarbon generation, accumulation, and evolution history in ultra-deeply-buried strata

The evolution mechanism of hydrocarbons in ultra-deeply-buried and ultra-old strata is the core issue of petroleum geology moving towards Deep Earth. Reconstructing the evolutionary history of ultra-deeply-buried hydrocarbons is the key to shedding light on deep hydrocarbon accumulation and evolution mechanisms. Furthermore, it can help point out directions for oil and gas exploration in Deep Earth. Anyue gas field in the central Sichuan Basin is the Frontier of deep natural gas exploration in China. This study selected the natural gas reservoirs of the Upper Sinian Dengying Formation in the central Sichuan Basin as the research object. By integrating analysis of natural gas geochemical characteristics, source rock evaluation, reservoir bitumen-source correlation, inclusion analysis, one-dimensional and two-dimensional hydrocarbon accumulation simulations, the generation and evolution of hydrocarbons in different structural regions, namely the inherited paleo-uplift and slope area in central Sichuan Basin, have been dynamically restored and compared. The results show that: 1) The natural gas of the ultra-deeply-buried Sinian Dengying formation in central Sichuan is typical oil-cracking gas from the paleo-oil reservoir. The Sinian gas is mainly sourced from the Qiongzhusi/Maidiping Formation. 2) The formation of Sinian gas reservoirs includes three stages: the formation of paleo-oil-reservoirs; the cracking of paleo-oil-reservoirs into paleo-gas-reservoirs; the adjustment of the paleo-gas-reservoirs. 3) Source rock and reservoir evaluation, quantitative solid bitumen analysis, and hydrocarbon accumulation simulation show that the natural gas accumulation conditions in the slope area are better than in the inherited uplift area. The scale of the paleo-oil-reservoirs in the slope area may be greater than that in the inherited uplift area.

Mid‐infrared dissolved CO2 measurement system using the ultra‐compact multipass cell

AbstractTo measure natural gas hydrate, a mid‐infrared dissolved CO2 measurement system is designed using the tunable diode laser spectroscopy with ultra‐compact multipass cell. The QCL laser of 4319 nm has a scanning range from 2315.05 to 2315.40 cm−1, which contains 12CO2 and 13CO2 for isotope measurement and wide range of concentration detection. The optimized 3f + 1f wavelength modulation method reduces the limit of detection to 7.1 ppbv. An ultra‐compact multi‐pass cell with effective optical path length of 6.3 m and small volume of 15 ml is designed to achieve the system response time of 40 s. The dissolved CO2 sensing system has been used in deep sea natural gas hydrate detection.

Logging evaluation of deep multi-type unconventional gas reservoirs in the Songliao basin, northeast China: Implications from continental scientific drilling

Multi-type unconventional gas-bearing reservoirs with different lithologies and gas accumulation potential occur in the deep part of the Songliao basin. However, the reservoirs are non-homogeneous, the gas components differ substantially, and not all types of gas-bearing reservoirs have been identified or evaluated. The International Continental Scientific Drilling Program (ICDP) is used as an example to conduct qualitative and quantitative evaluations of deep multi-type unconventional gas-bearing reservoirs using conventional and specialized logging data. The core test data are used to determine the physical properties. The porosity and permeability are compared and analyzed using different methods and models. The results show that the reservoirs have low to ultra-low porosity and ultra-low permeability. Based on the comparison of the rock mechanical parameters and mineral composition, brittleness evaluation parameters are proposed for different types of deep reservoirs in the study region. The mineral brittleness index is highly consistent with the brittleness index based on rock mechanics. An identification method for deep multi-type gas-bearing reservoir and a classification approach for different gas properties are established based on the logging response and parameter interpretation. The methane gas reservoirs have low density (DEN) and low compensated neutron logging (CNL) values and high acoustic (AC) time difference and high resistivity (RT) values. The CO2 gas reservoirs have lower RT values and higher CNL values than the hydrocarbon gas reservoirs. The comprehensive analysis of deep gas source rock conditions and of the source-reservoir relationship provides insights for the evaluation of deep multi-type unconventional gas reservoirs. The discovery of high hydrogen content is of significant importance for developing new areas for deep natural gas exploration.

Numerical and Experimental Investigation on Safety of Downhole Solid–Liquid Separator for Natural Gas Hydrate Exploitation

Deep water shallow natural gas hydrate (NGH) is a kind of clean energy and has entered the commercial exploitation stage. However, it produces a lot of seabed sediment in the process of large-scale mining, which not only easily causes undersea natural hazards, but also leads to pipeline equipment blockage and high energy consumption in the mining process. A downhole solid–liquid separator can effectively separate natural gas hydrate from sand and backfill sand in situ, which can effectively solve this problem. In this paper, the safety of a downhole solid–liquid separator desander under torsion conditions is determined by a test method. A numerical simulation method was used to simulate the tension and pressure of the downhole solid–liquid separator, and a modal simulation analysis and erosion analysis of the downhole solid–liquid separator were carried out. The experiments showed that the downhole solid–liquid separator could withstand 30 KN/m of torque, and a numerical simulation analysis showed that it could withstand 30 MPa of pressure and 50 KN of tension. The results show that the maximum stress is 116.56 MPa, and the maximum allowable stress is 235 MPa. The modal analysis showed that the downhole solid–liquid separator produces resonance at a frequency of about 93 Hz, resulting in large deformation, which should be avoided as far as possible. Through the erosion analysis, the life of the downhole solid–liquid separator was determined to be about 2.3 years. Numerical simulation and experimental results show that the designed downhole solid–liquid separator for natural gas hydrate can ensure safety.