Permian Gas Research Articles

The impact of exploration/appraisal activities on the recovery per well in North Perth Basin

The North Perth Basin (NPB) in Western Australia has experienced significant petroleum industry activity over the past 3 years (2021–2023), marked by the drilling of exploration and appraisal wells by various operators, along with notable merger and acquisition transactions. This flurry of drilling activity, coupled with the acquisition of new seismic data, have enhanced our understanding of the variability within the primary petroleum play levels – namely, the Permian ‘Kingia’ and High Cliff reservoirs. This understanding is crucial for assessing the future potential of domestic gas supply in Western Australia. This paper aims to elucidate how recent drilling efforts have narrowed the basin-wide portfolio of available gas prospects relative to the situation in early 2021, and how the landscape of undiscovered gas resources has evolved. This shift is attributed to both unsuccessful exploration attempts and revised estimates of well deliverability. Furthermore, an updated long-term production forecast for the NPB – considering existing gas pools and the newly assessed undiscovered resources – emphasises the urgent need to re-evaluate the narrative concerning gas availability for the domestic market. The Permian gas plays within the NPB have proven to be more intricate and unpredictable than previously believed. Nonetheless, their significance to the Western Australian economy is anticipated to be substantial for many years ahead.

Classification and Prediction Method for Dolomite Reservoirs in the Permian Maokou Formation in the Sichuan Basin

The Lower Permian Maokou Formation in the Hechuan area is one of the key horizons for natural gas exploration in the Sichuan Basin, showing a low degree of exploration and great exploration potential. The Lower Permian gas reservoir is mainly controlled by the reservoir, therefore it is subject to the development of the Maokou Formation reservoir. However, due to the strong heterogeneity and significant variations in physical properties of the Maokou Formation dolomite reservoir in the Hechuan area, there are significant differences in seismic response characteristics of reservoirs with different porosities. Through comprehensive analysis of gas testing wells in the Maokou Formation, criteria for reservoir classification were established based on lithology, average porosity, plane porosity, and thickness of dolomite reservoirs. The effective reservoirs in the Maokou Formation were divided into two types: high-porosity reservoirs and medium-porosity reservoirs. On the basis of establishing a physical quantity model for the Lower Permian carbonate rock in the research area, the rock physical characteristics and seismic response characteristics of reservoirs with different pores are determined through model forward modeling, and appropriate methods are selected for prediction. By using the optimization processing method of gathers and wavelet decomposition to remove sidelobes, the issue of seismic abnormal response caused by lateral velocity changes in the underlying Maokou Formation has been solved. The relative strength relationship of seismic response amplitude can effectively characterize the true situation of reservoir development. Then, by using post-stack inversion and pre-stack simultaneous inversion methods, the high-porosity and medium-porosity dolomite reservoirs in the Maokou Formation are classified and predicted, thereby to effectively improve the prediction accuracy of reservoirs, ultimately providing a reliable basis for the exploration and development of the Maokou Formation in the Hechuan area in the later stage.

Characteristics and main controlling factors of intra-platform shoal thin-layer dolomite reservoirs: A case study of Middle Permian Qixia Formation in Gaoshiti–Moxi area of Sichuan Basin, SW China

Based on the study of the distribution of intra-platform shoals and the characteristics of dolomite reservoirs in the Middle Permian Qixia Formation in the Gaoshiti–Moxi area of the Sichuan Basin, SW China, the controlling factors of reservoir development were analyzed, and the formation model of “intra-platform shoal thin-layer dolomite reservoir” was established. The Qixia Formation is a regressive cycle from bottom to top, in which the first member (Qi1 Member) develops low-energy open sea microfacies, and the second member (Qi2 Member) evolves into intra-platform shoal and inter-shoal sea with decreases in sea level. The intra-platform shoal is mainly distributed near the top of two secondary shallowing cycles of the Qi2 Member. The most important reservoir rock of the Qixia Formation is thin-layer fractured-vuggy dolomite, followed by vuggy dolomite. The semi-filled saddle dolomite is common in fracture-vug, and intercrystalline pores and residual dissolution pores combined with fractures to form the effective pore-fracture network. Based on the coupling analysis of sedimentary and diagenesis characteristics, the reservoir formation model of “pre-depositional micro-paleogeomorphology controlling shoal, sedimentary shoal controlling dolomite, penecontemporaneous dolomite benefiting preservation of pores, and late hydrothermal action effectively improving reservoir quality” was systematically established. The “first-order high zone” micro-paleogeomorphology before the deposition of the Qixia Formation controlled the development of large area of intra-platform shoals in Gaoshiti area during the deposition of the Qi2 Member. Shoal facies is the basic condition of early dolomitization, and the distribution range of intra-platform shoal and dolomite reservoir is highly consistent. The grain limestone of shoal facies is transformed by two stages of dolomitization. The penecontemporaneous dolomitization is conducive to the preservation of primary pores and secondary dissolved pores. The burial hydrothermal fluid enters the early dolomite body along the fractures associated with the Emeishan basalt event, makes it recrystallized into medium–coarse crystal dolomite. With the intercrystalline pores and the residual vugs after the hydrothermal dissolution along the fractures, the high-quality intra-platform shoal-type thin-layer dolomite reservoirs are formed. The establishment of this reservoir formation model can provide important theoretical support for the sustainable development of Permian gas reservoirs in the Sichuan Basin.

The Permian gas potential of the Taroom Trough, Queensland: new ideas to unlock a multi-TCF play

The Taroom Trough in Queensland is the main synclinal depression and southern extent of the Bowen Basin. Both the Bowen Basin and the overlying Surat Basin have been the focus of Australia’s coal seam gas (CSG) liquefied natural gas (LNG) export industry since 2014, but with CSG production now in decline and with a greater focus on domestic gas, it is timely to review the potential of new plays in this region. Although exploration and development in the Taroom Trough over the past decade have focussed on shallow Permian and Jurassic CSG resources, the early hydrocarbon potential of the trough was realised through conventional discoveries. Regardless of the reservoir, all conventional hydrocarbons in the trough have been typed to the same prolific Permian coals. These source rocks produce enormous volumes of oil and gas, yet only a small percentage of those volumes have been trapped in known conventional structures. This implies that a significant volume of oil and gas could remain trapped in tight reservoirs, including Fractured Thermally Mature Coals. Elixir Energy Limited plans to commence a drilling program in 2023 in ATP2044 (Grandis Gas Project) to unlock the gas potential of the Taroom Trough. The project will investigate the potential of Permian coals and sandstones at >3700 m depth using new understandings developed from recent studies into the critical role of elastic rock properties and stress anisotropy on coal fracture growth. This paper describes the opportunity that Elixir has identified and details the legacy technical work in the area and new research and ideas which have since evolved.

Characterization of pore structure in Carboniferous–Permian gas shales and tight sandstones of the coal-bearing succession in the Qinshui Basin, north China

Characterization of pore structure in Carboniferous–Permian gas shales and tight sandstones of the coal-bearing succession in the Qinshui Basin, north China

Formation Time and Material Source of Carbonate Cements in Permian Sandstone in the Ordos Basin, Western of China

Abstract Carbonate cements are an important type of cement in Permian tight gas reservoirs in the Ordos Basin. Moreover, the distribution of carbonate cements in sandstone provides an important basis for studying the fluid mechanism and genesis of cements and a scientific basis for investigating the physical properties of reservoirs and the underground distribution of oil and gas. Based on the observations of thin sections and temperature measurements of fluid inclusions, this study concludes that the carbonate cements in the study area are dominated by calcite and ferrous calcite and divided into three phases, where the latter two phases are dominant. The material source of carbonate cements is obtained via the thermal simulations of gold tubes in source rocks, temperature of fluid inclusions in carbonate cements, composition of fluid inclusions in quartz overgrowth, and analysis of carbon and oxygen isotopes. Results show that phase I calcite may be directly precipitated from the supersaturation of pore water by Ca2+ and CO32−. The CO32− in the phase II calcite and ferrous calcite stems from the CO2 generated in the hydrocarbon generation process of organic matter, while the CO32− in phase III calcite stems from the CO2 generated in the decarboxylation of organic acids. Ca2+ is derived from the dissolution of early carbonate cements in sandstone and conversion of smectite into illite in mudstone. The Permian sandstone in the Yishan Slope at the center of the basin is close to the source rock, and the carbon isotopic value of the carbonate cements, which is dominated by organic carbon, ranges between −7.5‰ and −19.0‰. However, the Permian sandstone in the Tianhuan Depression at the edge of the basin is far away from the source rock, with its carbon isotope value ranging from −5.9‰ to −8.7‰, which is probably due to the insufficient supply of organic carbon and a small amount of early inorganic CO2 remains in the reservoir.

Organic geochemical characteristics and gas prospectivity of Permian source rocks in western margin of Songliao Basin, northeastern China

The Permian in western margin of Songliao Basin is a strategic potential field of oil and gas resources in northeastern China, but the systematic researches since few boreholes were drilled up to Permian strata, as well as there is a lack of seismic and well-logging data. This paper presents the lithological composition of the Permian Formations on the basis of regional geological survey in western margin of Songliao Basin. A total of 60 mudstones and shales were collected to evaluate the organic geochemical and petrophysical characteristics and gas prospectivity of Permian source rocks. The Permian is composed of Shoushangou, Dashizai, Zhesi and Linxi Formation, which represent large sets of mudstones and shales, which are mainly deposited in a weakly to strongly reducing marine environment. The primary organic matter precursors in Permian were lower aquatic organisms such as zooplankton and algae, while a few samples of Linxi Formation indicate mixed sources of lower aquatic organisms and terrigenous higher plants. The Permian gas–prone source rocks are at over–mature stage with vitrinite reflectance Ro% = 2.01%–3.14% and mainly classified as fair to good quality and type II–III kerogens, and generally have a tricyclic terpane distribution pattern of C21>C23>C20, but Shoushangou Formation and Linxi Formation have subordinate patterns of C21>C20>C23 and C23>C21>C20, respectively. The residual organic matters in Permian source rocks have CH4 yields up to 24.34 mg/g∙TOC at EASY%Ro = 4.45%, which indicate the possibility of secondary gas generation at Ro% = 2.0%–3.5%. The pores and fractures are developed in Permian source rocks with widths of 5.28–18.64 μm, and mean values of porosity and permeability are 2.17% and 0.0043 × 10−3 μm2, respectively. The source–reservoir–cap rock assemblages in Carboniferous–Permian and Mesozoic sedimentary sequences are included in situ and near–source accumulation in Permian, and long–distance migration and accumulation in underlying Carboniferous and overlying Triassic, Jurassic and Cretaceous. The Permian system can be regarded as a potential gas exploration target in the western margin of Songliao Basin.

Carbon Isotope Kinetics Effect on the Natural Gas Accumulation: A Case Study of the Baimiao Area, Dongpu Depression, North China

Carbon isotope kinetics is developed from hydrocarbon generation kinetics for studying the natural gas accumulation process. On the basis of the kerogen pyrolysis experiments conducted in a closed gold tube autoclave system, the hydrocarbon generation kinetic parameters and carbon isotope kinetic parameters of the Shahejie Formation source rocks in the Qianliyuan sag are obtained by the Kinetics software and Excel spreadsheet software. In combination with the thermal and burial histories of the Qianliyuan sag, the long-term cumulative curve and periodic cumulative curve starting from 28.6 Ma under geological conditions are established. In combination with the geochemical parameters of the Carboniferous–Permian gas source rocks, the gas source and natural gas accumulation process in the Baimiao area are revealed. The results show that (1) the oil–gas reservoirs in the Baimiao area are formed earlier, and their accumulation time occurred from 28.6 to 27–25.8 Ma, and (2) the natural gas accumulation process in the Baimiao area was revealed to progress from the Shahejie 1 Formation depositional period to the Dongying Formation depositional period, the coal-type gas generated by the Carboniferous–Permian source rocks was accumulated in the Paleogene traps along the Lanliao fault and its derived fault systems, and these traps were formed during the Shahejie 2 Formation depositional period. Approximately 28.6 Ma, some oil-type gas generated by the Paleogene source rocks in the Qianliyuan sag accumulated in the traps formed during the early stage of the structural wing. Other oil-type gas migrated to the central part of the structure along the Duzhai fault and along a series of secondary faults in the Baimiao area, which then mixed with coal-type gas that accumulated in the early stage. At the end of the Dongying Formation depositional period, hydrocarbon generation ceased and the oil-type gas accumulation process was blocked from 27 to 25.8 Ma, which terminated the coal-type gas accumulation process. This work may provide some insights into the natural gas accumulation process and distribution in the Dongpu depression.

Shale Producers Adopt Geochemistry Fingerprinting to Quantify Cross-Well Production

Obtain a sample of reservoir rock, heat it up, add pressure, and then take a real close look at the drop of oil that comes out to find its unique “fingerprint.” At a high level, this is the emerging extraction and geochemistry process that more than two dozen tight-oil producers have recently adopted to solve one of the shale sector’s biggest mysteries: how does oil flow through the rock matrix and into a hydraulically fractured horizontal well? In a stacked formation, that question branches off into a few more: how much do neighboring horizontal wells communicate, which zones are co-producing the most, and how do these factors change over time? “The ground truth comes when you collect rock, and know exactly what depth that rock comes from, and then extract hydrocarbons from that rock to know the fingerprint of that depth,” said Faye Liu, the founder and chief executive of geochemistry startup RevoChem. Founded last year, the Houston-based firm has so far identified a geochemical fingerprint in more than 5,000 reservoir rocks and produced oil samples from more than 300 wells in nine different shale plays in North America and the Vaca Muerta Shale in Argentina. Every new sample sheds a bit more light on the complex flow patterns of unconventional reservoirs. Among RevoChem’s findings is that pad wells placed in different benches of a tight reservoir stand a high chance of experiencing some level of cross-well communication (Fig. 1). “All of your oil is a mixture coming from multiple zones,” explained Liu who was formerly a geochemist with Conoco Phillips. She noted that despite how they appear in modeling software, the evidence from geochemical fingerprinting shows that hydraulic fractures often extend out of their target zone and into other oil-rich layers of rock. “Essentially, every operator is experiencing the same•process.” A primary goal for adopters of the technology is to describe that vertical drainage in detail—and how the profile changes over time. “In a stacked development, every subsurface professional must be engaged with that understanding,” said Toby Deen, a senior engineer with private Permian oil and gas company Felix Energy, which started conducting time-lapse fingerprinting earlier this year. In addition to vertical production allocation, operators are using geochemical fingerprinting to overcome the difficulty that other diagnostics have had in assessing the related parameter of fracture height. If wells are believed to have a fracture height somewhere in the range of 400–600 ft, then using wider distances between vertically separated wells to avoid interference is justified. However, if the geochemistry shows that only 5–10% of the cross-well production is from the extreme tips of such a fracture network, then wider spacing may not be optimal (Fig. 2). What would make future spacing decisions easier is if an operator could prove that a majority of production is coming from an area just 200–300 ft away from the wellbore. “That means there is a lot of infill potential,” said Liu.

Oilfield Flares Provide a Glaring Reminder of the Drive To Produce More Oil

Natural gas flared in just two major US shale plays exceeded the amount of gas consumed last year in Colombia and Israel. The prolific waste from the Permian and the Bakken (Figs. 1 and 2) is a side effect of rising oil production in plays where gas growth is so strong pipeline construction cannot keep up. Flaring is a glaring reminder of the realities of the never-ending rush to drill that is driving down the cost of oil and gas around the globe. These oil-producing wells also produce more gas than processing plants and pipelines can move to market. Pipelines and refineries have recognized that ultralight oil in the Permian is fundamentally different from West Texas Intermediate (WTI), with a make-up that puts it somewhere between oil and gas•liquids. As those wells age, oil production falls as the output shifts to gas. And the cost of sustaining production for the vast majority of producers has consistently exceeded the cash generated by these wells (Fig.• 3). The gap between capital expenditures and revenues was “a staggering $4.7•billion” during the first quarter of 2019, according to a study by Alisa Lukash, a senior analyst on Rystad Energy’s North American shale team, who described it as a “tremendous overspend.” Both the US Energy Information Administration (EIA) and Rystad have raised outlooks that already predicted strong US oil growth. Flaring growth and overspending have accompanied a rebound in growth in the Permian and Bakken, which are the flaring leaders by far in the US. More than half of the total comes from the Permian, which has surpassed the Bakken by more than tripling the volume of gas burned per day since early 2017. The severity of the problem, though, is more acute in the Bakken. While Rystad said about 5% of the Permian gas is flared, in the Bakken, 19% of the gas is flared, according to the oil and gas division of the North Dakota Industrial Commission. The Permian produces far more gas but has the advantage of being close to growing markets for it—chemical plants, export pipelines to Mexico, and natural gas liquefaction facilities—while North Dakota is a distant option for Midwestern markets well supplied by other plays. Limited pipeline capacity means those shippers without contracts ensuring they can move their gas are paid little or less than nothing—prices at Waha gas hub in west Texas repeatedly sank into negative territory over the winter, and pipeline shortages will linger until a big new pipeline goes into service. Oil pipeline construction also has lagged supply growth in the Bakken. Trains and trucks can ship oil, but that is a costly option. North Dakota oil regulators reported that Bakken prices hovered around $50/bbl early this year when the benchmark US oil grade was about $10/bbl higher.

Features of the structure, sedimentary complexes and hydrocarbon systems of the Leno-Vilyui oil and gas basin

The Leno-Vilyui basin, consisting of the Vilyui syneclise and the Pre-Verkhoyansk deflection, is made of a thick (more than 10 km) sedimentary rock that has formed over a very long geological history (at least 1 billion years). Almost all of the fields identified here are confined to two gross structures, and gas is predominant in the composition of hydrocarbon reservoirs. Studies show that the main hydrocarbon system (Permian-Cretaceous) in most areas is formed by Permian gas source formations, deposited in continental environments with predominance of type III kerogen. Systems with a significant proportion of liquid hydrocarbons may be associated with areas of predominantly marine sedimentation (Pre-Verkhoyansk deflection) or more ancient (Lower Paleozoic) sediments. In all cases, natural reservoirs are distinguished by a complex structure due to sharp facial variability and intensive secondary transformations.

The geochemistry and origin of lower Permian gas in the northwestern Sichuan basin, SW China

The lower Permian series in northwestern Sichuan basin of China is a favorable region for natural gas accumulation with several potential source rocks and high-quality reservoirs. However, the tectonic evolution in this area has gone through long-term and complicated activities and the origin of gases in the lower Permian series is complex. For the wise exploration strategies planning, the origin and accumulation of natural gas in lower Permian reservoir have been addressed. And the results reveal that: (1) Three sets of potential source rocks, including the mudstone of Lower Cambrian Qiongzhusi formation, Lower Silurian Longmaxi formation and the marine carbonate source rocks of Lower Permian, have been identified as the gas sources in Lower Permian reservoirs. (2) The gases mainly contain by hydrocarbon gases, with the ratio of C1/C2+ > 0.99, and the characteristics of carbon isotopes are various and several wells’ are reversed or close to reversed. The δ13C2 values of Hewanchang and Wujiaba gas fields are ranging from −33.35‰ to −36.34‰(PDB), similar to the production of sapropelic organic matter. The Shuangyushi and Kuangshanliang gas fields, with the δ13C2 values ranging from −28‰ to −30‰(PDB), are source mixed gas. And the δ13C2 values of Jiulongshan gas field are the heaviest with the value range from −25.23‰ to −28.4‰(PDB). (3) The biomarkers of reservoir extracts are consistent with those of the lower Permian source rock, but the bitumen scales in lower Permian are not as much as those in the lower Cambrian or Lower Silurian series, which reveals that the crude oil creaked gas formed in lower Permian series falls a great deal than that in Cambrian and Silurian series. Based on the comprehensive researches of natural gas composition, carbon isotope, biomarkers of extract and other parameters, the natural gases in lower Permian series are mixed by the crude oil creaked gas from deep formation and the lower Permian source rock, and the scale of fracture determines the amount of creaked gas mixed in the lower Permian reservoir.

Sedimentary features and exploration targets of Middle Permian reservoirs in the SW Sichuan Basin

The exploration direction and targets for the large-scale Middle Permian gas reservoirs in the Sichuan Basin are hot spots and challenges in current exploration researches. The exploration successes of large gas field of Cambrian Longwangmiao Formation in Gaoshiti-Moxi region, Central Sichuan Basin, indicated that prospective sedimentary facies belt was the basis for the formation of large gas fields. In this paper, based on seismic data, outcrop data and drilling data, the tectonic framework and sedimentary features of the Middle Permian in the SW Sichuan Basin were comprehensively studied. The following conclusions were reached from the perspective of sedimentary facies control: (1) during the Middle Permian, this region was in shallow water gentle slope belts with high energy, where thick reef flat facies were deposited; (2) the basement was uplifted during Middle Permian, resulting in the unconformity weathering crust at the top of Maokou Formation due to erosion; the SW Sichuan Basin was located in the karst slope belt, where epigenic karstification was intense; and (3) reef flat deposits superimposed by karst weathering crust was favorable for the formation of large-scale reef flat karst reservoirs. Based on the combination of the resources conditions and hydrocarbon accumulation conditions in this region, it was pointed out that the Middle Permian has great potential of large-scale reef flat karst gas reservoir due to its advantageous geological conditions; the Middle Permian traps with good hydrocarbon accumulation conditions were developed in the Longmen Mountain front closed structural belt in the SW Sichuan Basin and Western Sichuan Basin depression slope belt, which are favorable targets for large-scale reef flat karst reservoirs.

Geological significance of paleo-aulacogen and exploration potential of reef flat gas reservoirs in the Western Sichuan Depression

Confirming thick hydrocarbon generation center and discovering thick porous reservoirs are two key factors to start the Permian gas exploration of the Western Sichuan Depression. In this paper, the Sinian-Cambrian structures of this area were studied by adopting the layer-flattening technology and the Lower Paleozoic thickness map was prepared in order to describe the Permian hydrocarbon generation center. Then, combined with seismic facies analysis and field outcrop bioherm discovery, the distribution of Middle Permian reef flat reservoirs were predicted. Finally, the favorable conditions for reef flat reservoir dolomitization were analyzed based on fault features. The study indicates that: (1) Sinian top represents a huge depression in the profile flatted by the reflecting interface of Permian bottom, with normal faults filled by thick Lower Paleozoic sediments at both sides, revealing that a aulacogen formed during the Khanka taphrogeny exists in the Western Sichuan Depression, where very thick Cambrian strata may contain hydrocarbon generation center, making Permian strata have the material conditions for the formation of large gas pools; (2) the Middle Permian strata in the Western Sichuan Depression exhibit obvious abnormal response in reef flat facies, where three large abnormal bands are developed, which are predicted as bioherm complex combined with the Middle Permian bioherm outcrop discoveries in surface; and (3) deep and large extensional faults are developed in reef flat margin, manifesting as favorable conditions for the development of dolomite reservoirs. The results show that the Middle Permian traps in the Western Sichuan Depression contain resources up to 7400 × 108 m3, showing significant natural gas exploration prospects. By far, one risk exploration well has been deployed.

Salt kinematics and regional tectonics across a Permian gas field: a case study from East Frisia, NW Germany

This study presents a reconstruction of the tectonic history of an Upper Rotliegend tight gas field in Northern Germany. Tectonism of the greater study area was influenced by multiple phases of salt movement, which produced a variety of salt-related structural features such as salt walls, salt diapirs as well as salt glaciers (namakiers). A sequential 2D retro-deformation and stratal backstripping methodology was used to differentiate mechanisms inducing salt movement and to discuss their relation to regional tectonics. The quantitative geometric restoration included sedimentary balancing, decompaction, fault-related deformation, salt movement, thermal subsidence, and isostasy to unravel the post-depositional tectonic overprint of the Rotliegend reservoir rock. The results of this study indicate that reactive salt diapirism started during an Early Triassic interval of thin-skinned extensional tectonics, followed by an active diapirism stage with an overburden salt piercement in the Late Triassic, and finally a period of intensive salt surface extrusion and the formation of salt glaciers (namakiers) in Late Triassic and Jurassic times. Since the Early Cretaceous, salt in the study area has been rising by passive diapirism.

Origin of marine sour natural gas and gas-filling model for the Wolonghe Gas Field, Sichuan Basin, China

The chemical and isotopic composition of natural gases from the Wolonghe Gas Field, Sichuan Basin, Southwest China, was investigated to assess the potential gas sources and reconstruct the gas-filling history of the reservoirs. All natural gases in this field are dominated by gaseous hydrocarbons (C1–C3) with varied amounts of non-hydrocarbon components (CO2, H2S and N2). The H2S content varies with reservoir intervals. It ranges from zero to 1.84% with an average of 0.37% in the Carboniferous reservoir, from 0.05% to 0.76% with an average of 0.30% in the Permian reservoir, and from 1.09% to 18.83% with an average of 5.39% in the Lower Triassic reservoir. The gas dryness coefficient (C1/C1–3) ranges from 0.97 to 1.0 with an average of 0.99. The carbon isotopic compositions of methane and its homologues in the Wolonghe Gas Field vary widely, with δ13C1⩾δ13C2<δ13C3 in the Carboniferous and Permian gas reservoirs, and δ13C1<δ13C2<δ13C3 in the Lower Triassic Jialingjiang Formation gas reservoirs. The δD1 values range from −140‰ to −100‰, with an average of −124.5‰. The δ34SH2S values in the field extend from 5.7‰ to 31.0‰, with δ34SH2S values in the Lower Triassic Jialingjiang Formation reservoirs being much higher than those in the Carboniferous and Permian reservoirs. The sour natural gases in the field originated from cracking of oil and were sourced from the marine sapropelic organic matter at high maturity levels. The natural gases underwent alteration by thermochemical sulfate reduction (TSR). Although the limited extent TSR occurred in the Carboniferous and Permian gas reservoirs, the TSR alteration is likely to have caused the high gas dryness and the 13C enrichment of CH4. The present low content of H2S in the Carboniferous and Permian gases would be related to the loss of H2S dissolved in water under the reconstruction of these gas reservoirs. In contrast, the high H2S in the Jialingjiang Formation gases is determined by both the favorable TSR conditions in the Lower Triassic reservoirs and the favorable preservation conditions provided by the Lower-Middle Triassic gypsum.The Wolonghe natural gas system is characterized by multi-pay zones, multi-source supply and multi-type layers. The gas generated from Silurian source rocks migrated into the Carboniferous reservoir through faults and fractures and was trapped beneath the Permian Liangshan Formation shale, whereas the natural gas in the Permian and Lower Triassic Jialingjiang Formation was generated and preserved in its own formations with the overlying gypsum acting as a cap rock.

Structural style variation and its impact on hydrocarbon traps in central Fars, southern Zagros folded belt, Iran

The Fars area is the main target for Permian gas exploration in the Zagros fold belt. It contains approximately 15 percent of the world’s proven gas reserves. The geometrical characteristics of the folded structures change dramatically across the N–S trending Gavbandi High. We used seismic profiles, well data, magnetic survey information and field observations to show that thickness variation of the sedimentary pile inherited from basement geometry is the main reason behind structural style variation in this area which occurred during the Zagros folding. Differences in thickness were more significant in Early-Middle Paleozoic time and decreased considerably upward in time. The total thickness of the Lower Paleozoic succession in the eastern side of the Gavbandi High is approximately 40–50% thicker than on the summit of this basement high. Sedimentary pinch-outs through Cretaceous and Tertiary times indicate that the activity of the basement faults decreased but did not stop. The impact on hydrocarbon traps of the pre-folding basin architecture and the differences in the behavior of the sedimentary cover after Miocene folding is discussed and documented.

Products and timing of diagenetic processes in Upper Rotliegend sandstones from Bebertal (North German Basin, Parchim Formation, Flechtingen High, Germany)

AbstractAeolian-fluvial Upper Rotliegend sandstones from Bebertal outcrops (Flechtingen High, North Germany) are an analogue for deeply buried Permian gas reservoir sandstones of the North German Basin (NGB). We present a paragenetic sequence as well as thermochronological constraints to reconstruct the diagenetic evolution and to identify periods of enhanced mesodiagenetic fluid–rock reactions in sandstones from the southern flank of the NGB. Bebertal sandstones show comparatively high concentrations of mesodiagenetically formed K-feldspar but low concentrations of illite cements. Illite-rich grain rims were found to occur preferentially directly below sedimentary bounding surfaces, i.e. aeolian superimposition surfaces, and indicate the lowest intergranular volume. Illite grain rims also indicate sandstone sections with low quartz and feldspar cement concentrations but high loss of intergranular volume due to compaction.40Ar–39Ar age determination of pronounced K-feldspar grain overgrowths and replacements of detrital grains indicates two generations: an early (Triassic) and a late (Jurassic) generation. The latter age range is similar to published diagenetic illite ages from buried Rotliegend reservoir sandstones. The first generation suggests an early intense mesodiagenetic fluid flow with remarkably high K+activity synchronous with fast burial of proximal, initial graben sediments on the southern flank of the NGB. Accordingly, zircon fission-track data indicate that the strata already reached the zircon partial annealing zone of approximately 200°C during early mesodiagenesis. Zircon (U–Th)/He ages (92 ± 12 Ma) as well as apatite fission-track ages (~ 71–75 Ma) indicate the termination of mesodiagenetic processes, caused by rapid exhumation of the Flechtingen High during Late Cretaceous basin inversion.

Helium and argon isotope geochemistry of natural gases in China’s petroliferous basins

The age-accumulation effect of 40Ar in hydrocarbon source rocks was discussed in accordance with the decay law of radioactive elements. In terms of the mean values of 40Ar/36Ar, the old Sinian gas reservoirs (mean values of 40Ar/36Ar: 7009) were definitely distinguished from the Permian gas reservoirs (mean values of 40Ar/36Ar: 1017) in Weiyuan, Sichuan Province, and the gas source of the Permian gas reservoir (mean values of 40Ar/36Ar: 5222) in well Wei-7 with the Weiyuan structure is defined as the Sinian system. Based on the values of 40Ar/36Ar, the coal-type gases (The source rocks are of the C-P system; mean values of 40Ar/36Ar: 1125) are definitely distinguished from the oil-type gases (The source rocks are of the Tertiary system; mean values of 40Ar/36Ar: 590) in the Tertiary reservoirs of the Zhongyuan Oilfield. Besides, 40Ar/36Ar values also have a positive effect on the oil-source correlation of oil reservoirs in ancient hidden mountains. According to the crust-mantle interchange information reflected by 3He/4He values, petroliferous provinces in China can be divided into three major tectonic regions. (1) The eastern active region: The crust-mantle volatile matter exchanges actively, and the 3He/4He values are mainly around 10−6, partly around 10−7. (2) The central stable region: The 3He/4He values are all around 10−8. (3) The western sub-stable region: The 3He/4He values are mainly around 10−8, and around 10−7 on the edges of the basins. Helium contents of some gas wells in China’s eastern petroliferous region reach the industrial abundance (He≈0.05%–0.1%), the 3He/4He values reach 10−6, and the equivalent values for the mantle-source components in helium gas can reach 30%–50%. As viewed from this, a new type of crust-mantle composite helium resources has been proposed. Geneses of some CO2 gas reservoirs in the east of China and some issues concerning mantle-source methane were discussed in the light of the helium and carbon isotopes of CO2 and CH4 in natural gases. In the discussion on helium isotopic characteristics of inclusions in the reservoirs, it was discovered that the 3He/4He values are close to those in natural gases. That is to say, this phenomenon is related to regional tectonism. The 3He/4He, CO2/3He and CH4/3He data were used to discuss the tectonic activities of fault zones in a certain number of regions in China.

Factors controlling tight gas sandstone reservoir quality in the Whicher Range gas field, Southern Perth Basin, Western Australia

There are limited studies characterising the Willespie Formation, a Permian tight gas sandstone in the southern Perth Basin of Western Australia. Consequently, the main factors controlling the reservoir quality, lateral reservoir connectivity and fluid flow mechanism remain unknown. Available data from five Whicher Range wells—including wireline logs, seismic, core data, well reports and petrographic data—were studied to define the syn-depositional and post-depositional events affecting the reservoir rock quality. Based on analysis of the aforementioned data, the Willespie Formation is interpreted to have been deposited under predominantly fluvial conditions in an ancient rift basin of continental origin with no marine influence. The sedimentary environments were laterally varied, as inferred from discontinuous facies formed by meandering channels, crevasse splay and flood plain settings that were mainly controlled by the Permian tectonic setting. Extensive compaction due to ductile grain deformation, as well as clay and calcite cements—filling pores and replacing grains—are the main post-depositional factors affecting the reservoir quality of the medium–coarse-grained, poorly sorted litharenitic sandstones of the Willespie Formation. Combined syn-depositional parameters—controlling the composition and the texture of the sandstone—and post-depositional diagenetic events have had a critical control on the distinctive poor porosity (8% average) and very low permeability of this tight gas sandstone reservoir.