scholarly journals Hydrocarbon-Generating Potential of Eocene Source Rocks in the Abakaliki Fold Belt, Nigeria / Potencial za nastanek oglikovodikov v eocenskih izvornih kamninah nariva Abakaliki

2020 ◽  
Vol 66 (4) ◽  
pp. 223-233
Author(s):  
O.A. Oluwajana ◽  
A.O. Opatola ◽  
O.B. Ogbe ◽  
T.D. Johnson
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Threshold Value ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Fold Belt ◽  
Gaseous Hydrocarbon ◽  
Geochemical Model ◽  
The One ◽  
Rock Eval

AbstractSubsurface information on source rock potential of the Eocene shale unit of the Abakaliki Fold Belt is limited and has not been widely discussed. The total organic carbon (TOC) content and results of rock-eval pyrolysis for nine shale samples, as well as the one-dimensional (1D) geochemical model, from an exploration well in the Abakaliki Fold Belt were used to evaluate the source rock potentials and timing of hydrocarbon generation of Lower Eocene source rocks. The TOC content values of all the samples exceeded the minimum threshold value of 0.5 wt.% required for potential source rocks. A pseudo-Van Krevelen plot for the shale samples indicated Type II–III organic matter capable of generating gaseous hydrocarbon at thermally mature subsurface levels. The 1D burial model suggests that the Eocene source rock is capable of generating oil and gas at the present time. The modelled transformation ratio trend indicates that a fair amount of hydrocarbon has been expelled from the source rocks. The results of this study indicate that the Eocene source units may have charged the overlying thin Eocene sand bodies of the Abakaliki Fold Belt.

scholarly journals New exploration strategy in igneous petroliferous basins – Enlightenment from simulation experiments

2018 ◽  
Vol 36 (4) ◽  
pp. 971-985
Author(s):  
Qingqiang Meng ◽  
Jiajun Jing ◽  
Jingzhou Li ◽  
Dongya Zhu ◽  
Ande Zou ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Liquid Hydrocarbon ◽  
Hydrogen Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Simulation Experiments ◽  
Gaseous Hydrocarbon ◽  
Oil And Gas Fields ◽  
Gaseous Hydrocarbons ◽  
Hydrocarbon Productivity

There are two kinds of relationships between magmatism and the generation of hydrocarbons from source rocks in petroliferous basins, namely: (1) simultaneous magmatism and hydrocarbon generation, and (2) magmatism that occurs after hydrocarbon generation. Although the influence of magmatism on hydrocarbon source rocks has been extensively studied, there has not been a systematic comparison between these two relationships and their influences on hydrocarbon generation. Here, we present an overview of the influence of magmatism on hydrocarbon generation based on the results of simulation experiments. These experiments indicate that the two relationships outlined above have different influences on the generation of hydrocarbons. Magmatism that occurred after hydrocarbon generation contributed deeply sourced hydrogen gas that improved liquid hydrocarbon productivity between the mature and overmature stages of maturation, increasing liquid hydrocarbon productivity to as much as 451.59% in the case of simulation temperatures of up to 450°C during modelling where no hydrogen gas was added. This relationship also increased the gaseous hydrocarbon generation ratio at temperatures up to 450°C, owing to the cracking of initially generated liquid hydrocarbons and the cracking of kerogen. Our simulation experiments suggest that gaseous hydrocarbons dominate total hydrocarbon generation ratios for overmature source rocks, resulting in a change in petroleum accumulation processes. This in turn suggests that different exploration strategies are warranted for the different relationships outlined above. For example, simultaneous magmatism and hydrocarbon generation in an area means that exploration should focus on targets likely to host large oilfields, whereas in areas with magmatism that post-dates hydrocarbon generation the exploration should focus on both oil and gas fields. In addition, exploration strategies in igneous petroliferous basins should focus on identifying high-quality reservoirs as well as determining the relationship between magmatism and initial hydrocarbon generation.

scholarly journals GEOCHEMICAL AND GEOSTATISTICAL ASSESSMENT OF CRETACEOUS COALS AND SHALES IN SOME NIGERAIN SEDIMENTARY BASINS FOR THEIR HYDROCARBON PRONESS AND MATURITY LEVELS

2020 ◽  
Vol 1 (2) ◽  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Linear Regression Analysis ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Type Iii ◽  
Limit Value ◽  
The Impact

The Rock–Eval pyrolysis and LECO analysis for 9 shale and 12 coal samples, as well as, geostatistical analysis have been used to investigate source rock characteristics, correlation between the assessed parameters (QI, BI, S1, S2, S3, HI, S1 + S2, OI, PI, TOC) and the impact of changes in the Tmax on the assessed parameters in the Cretaceous Sokoto, Anambra Basins and Middle Benue Trough of northwestern, southeastern and northcentral Nigeria respectively. The geochemical results point that about 97% of the samples have TOC values greater than the minimum limit value (0.5 wt %) required to induce hydrocarbon generation from source rocks. Meanwhile, the Dukamaje and Taloka shales and Lafia/Obi coal are found to be fair to good source rock for oil generation with slightly higher thermal maturation. The source rocks are generally immature through sub-mature to marginal mature with respect to the oil and gas window, while the potential source rocks from the Anambra Basin are generally sub-mature grading to mature within the oil window. The analyzed data were approached statistically to find some relations such as factors, and clusters concerning the examination of the source rocks. These factors were categorized into type of organic matter and organic richness, thermal maturity and hydrocarbon potency. In addendum, cluster analysis separated the source rocks in the study area into two groups. The source rocks characterized by HI >240 (mg/g), TOC from 58.89 to 66.43 wt %, S1 from 2.01 to 2.54 (mg/g) and S2 from 148.94 to 162.52 (mg/g) indicating good to excellent source rocks with kerogen of type II and type III and are capable of generating oil and gas. Followed by the Source rocks characterized by HI <240 (mg/g), TOC from 0.94 to 36.12 wt%, S1 from 0.14 to 0.72 (mg/g) and S2 from 0.14 to 20.38 (mg/g) indicating poor to good source rocks with kerogen of type III and are capable of generating gas. Howeverr, Pearson’s correlation coefficient and linear regression analysis shows a significant positive correlation between TOC and S1, S2 and HI and no correlation between TOC and Tmax, highly negative correlation between TOC and OI and no correlation between Tmax and HI. Keywords- Cretaceous, Geochemical, Statistical, Cluster; Factor analyses.

scholarly journals Source rock potential of the Late Miocene Metochia formation of Gavdos Island, Greece

2017 ◽  
Vol 47 (2) ◽  
pp. 871
Author(s):  
I. Pyliotis ◽  
A. Zelilidis ◽  
N. Pasadakis ◽  
G. Panagopoulos ◽  
E. Manoutsoglou
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Late Miocene ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Low Oxygen ◽  
Crete Island ◽  
Good Potential ◽  
The Rich ◽  
Rock Eval

Rock-Eval method was used to analyze 53 samples from late Miocene Metochia Formation of Gavdos Island (south of Crete Island) in order to characterize the contained organic matter and to evaluate its potential as source rock. The samples were collected from Metochia Section which consists of about 100 m thick marlssapropels alternations. Organic matter analysis showed that the studied succession could be subdivided into two parts. The lower one, which is generally rich in organic matter and the upper one, which is poor. In the lower part the rich horizons in organic matter are characterized by Kerogen type II, III and IV, with low oxygen content, and with fair to very good potential for gas and/or oil hydrocarbon generation. Additionally, the studied samples are thermally immature. Taking into account that the studied area has never been buried in such a depth to reach conditions of maturation, as well as, that the studied section in Gavdos is connected with Messara basin located in the northeastern and, finally, that the main part of Gavdos basin, which is situated between Gavdos and Crete islands, has continuously encountered subsidence, we could conclude that sediments of Metochia Formation could act as source rocks but in the more deep central part of the Gavdos basin.

Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

2016 ◽  
Author(s):  
Samuel Salufu ◽  
Rita Onolemhemhen ◽  
Sunday Isehunwa
Keyword(s):  
Case Studies ◽  
Source Rock ◽  
Oil And Gas ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Reservoir Rock ◽  
Hydrocarbon Generation ◽  
Geochemical Analysis ◽  
Anambra Basin ◽  
Oil Generation

ABSTRACT This paper sought to use information from outcrop sections to characterize the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin in minimizing uncertainty and risk that are allied with exploration and field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. The methods of study includes detailed geological, stratigraphical, geochemical, structural,, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty eight samples of shale were collected from these Basins; geochemical analysis (rockeval) was performed on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software in order to properly characterize the potential source rock(s) and reservoir rock(s) in the basins, and factor(s) that can favour hydrocarbon traps. The results of the geological, stratigraphical, sedimentological, geochemical, and structural, were used to developed a new model for hydrocarbon generation in the Basins. The result of the geochemical analysis of shale samples from the Anambra Basin shows that the TOC values are ≥ 1wt%, Tmax ≥ 431°C, Vitrinite reflectance values are ≥ 0.6%, and S1+S2 values are &gt; 2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. The shale samples from Abakaliki Basin shows that S1+S2 values range from&lt; 1 – 20mg/g, TOC values range from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from423°C – 466°C. This result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Abakaliki Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage as a result of S1+S2 values lesser than 2.5mg/g despite TOC values of ≥ 0.5wt% and vitrinite reflectance values of ≥ 0.6%. The novelty of this study is that the study has been able to show that here there is much more oil than the previous authors claimed, and the distribution of this oil and gas in the basins is controlled by two major factors; the pattern of distribution of the materials of the source rock prior to subsidence and during the subsidence period in the basin, and the pattern and the rate of tectonic activities, and heat flow in the basin. If these factors are known, it would help to reduce the uncertainties associated with exploration for oil and gas in the two basins.

KITCHENS, KETTLES AND CUPS OF HYDROCARBONS, VICTORIAN OTWAY BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 285
Author(s):  
K. Mehin ◽  
A.G. Link
Keyword(s):  
Source Rock ◽  
Early Cretaceous ◽  
Bulk Composition ◽  
Source Rocks ◽  
Eastern Region ◽  
Hydrocarbon Generation ◽  
Good Source ◽  
Oil Generation ◽  
Close Proximity ◽  
Rock Eval

Evaluation of Early Cretaceous source rocks within the onshore Victoria Otway Basin has revealed that thick, mature shales containing predominantly gas-prone and in local concentrations, oil-prone macerals exist northwest of Portland, in the Tyrendarra Embayment, and around the Port Campbell region.Current results of Rock-Eval, bulk composition, gas chromatography, and biomarker analyses, coupled with geohistory and hydrocarbon generation interpretations, indicate that at least three phases of oil generation and expulsion occurred within the basin. The earliest phase, which coincided with the maximum heatflow in the crust around 100 Ma, resulted in the charging of the existing stratigraphic/shoestring traps of the basin. The second and third phases occurred in the eastern end of the basin at around 85 and 60 Ma. There is also evidence to suggest that structural traps of the eastern areas were formed later, during Oligocene time, and that these traps are probably still receiving late-stage charges of hydrocarbons.Although the sparse well density in the basin has resulted in limited, non-uniforin sampling opportunities, several regions with good Early Cretaceous source rocks can be recognised. Some of these good source rock areas are in close proximity to the several known hydrocarbon shows and producing fields. These current studies, which also include a source rock risk analysis indicating source rock adequacy, show that locations for future exploration could include the Casterton-Portland-Mt Gambier western region, the Peterborough-Port Campbell eastern region, and the prospective close peripheries and offshore extensions of these regions.

scholarly journals Effects of igneous intrusions on source rock in the early diagenetic stage: A case study on Beipiao Formation in Jinyang Basin, Northeast China

2020 ◽  
Vol 12 (1) ◽  
pp. 990-1002
Author(s):  
Shouliang Sun ◽  
Tao Zhang ◽  
Yongfei Li ◽  
Shuwang Chen ◽  
Qiushi Sun
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Vitrinite Reflectance ◽  
Scientific Basis ◽  
Source Rocks ◽  
Temperature History ◽  
Hydrocarbon Generation ◽  
Intrusive Body ◽  
Geochemical Parameters

AbstractMesozoic intrusive bodies play an important role in the temperature history and hydrocarbon maturation of the Jinyang Basin in northeastern China. The Beipiao Formation, which is the main source rock in Jinyang Basin, was intruded by numerous igneous bodies and dykes in many areas. The effects of igneous intrusive bodies on thermal evolution and hydrocarbon generation and migration in the Beipiao Formation were investigated. A series of samples from the outcrop near the intrusive body were analyzed for vitrinite reflectance (R0%) and other organic geochemical parameters to evaluate the lateral extension of the thermal aureole. The R0 values of the samples increase from a background value of ∼0.9% at a distance above 200 m from the intrusive body to more than 2.0% at the vicinity of the contact zone. The width of the altered zone is equal to the thickness of the intrusive body outcropped in the field. Organic geochemical proxies also indicate the intrusive body plays a positive and beneficial role in the formation of regional oil and gas resources. Due to the influence of the anomalous heat from the intrusive body, the hydrocarbon conversion rate of the source rocks of the Beipiao Formation was significantly improved. The accumulation properties and the storage capacity of the shales also greatly improved due to the intrusive body as indicated by the free hydrocarbon migration in the shales. This new understanding not only provides a reliable scientific basis for the accurate assessment of oil and gas genesis and resources in the Jinyang Basin but also provides guidance and reference for oil and gas exploration in the similar type of basin.

Unconventional Shale Play in Oman: Preliminary Assessment of the Shale Oil / Shale Gas Potential of the Silurian Hot Shale of the Southern Rub al-Khali Basin

2015 ◽  
Author(s):  
Jamal A. Madi ◽  
Elhadi M. Belhadj
Keyword(s):  
Source Rock ◽  
Shale Gas ◽  
Oil And Gas ◽  
Source Rocks ◽  
Geochemical Data ◽  
Hydrocarbon Generation ◽  
Shale Oil ◽  
Lower Silurian ◽  
History Of ◽  
Oil Gas

Abstract Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2. Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

scholarly journals Oil And Gas Generation History Based On Burial History Reconstruction And Thermal Maturity Modeling Of Petroleum Systems In Northern Iraq

2020 ◽  
Vol 10 (4) ◽  
pp. 95-120
Author(s):  
Rzger Abdulkarim Abdula
Keyword(s):  
Source Rock ◽  
Late Cretaceous ◽  
Oil And Gas ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Gas Generation ◽  
Northern Iraq ◽  
Oil Generation

Burial history, thermal maturity, and timing of hydrocarbon generation were modeled for five key source-rock horizons at five locations in Northern Iraq. Constructed burial-history locations from east to west in the region are: Taq Taq-1; Qara Chugh-2; Zab-1; Guwair-2; and Shaikhan-2 wells. Generally, the thermal maturity status of the burial history sites based on increasing thermal maturity is Shaikhan-2 < Zab-1 < Guwair-2 < Qara Chugh-2 < Taq Taq-1. In well Qara Chugh-2, oil generation from Type-IIS kerogen in Geli Khana Formation started in the Late Cretaceous. Gas generation occurred at Qara Chugh-2 from Geli Khana Formation in the Late Miocene. The Kurra Chine Formation entered oil generation window at Guwair-2 and Shaikhan-2 at 64 Ma and 46 Ma, respectively. At Zab-1, the Baluti Formation started to generate gas at 120 Ma. The Butmah /Sarki reached peak oil generation at 45 Ma at Taq Taq-1. The main source rock in the area, Sargelu Formation started to generate oil at 47, 51, 33, 28, and 28 Ma at Taq Taq-1, Guwair-2, Shaikhan-2, Qara Chugh-2, and Zab-1, respectively. The results of the models demonstrated that peak petroleum generation from the Jurassic oil- and gas-prone source rocks in the most profound parts of the studied area occurred from Late Cretaceous to Middle Oligocene. At all localities, the Sargelu Formation is still within the oil window apart from Taq Taq-1 and Qara Chugh-2 where it is in the oil cracking and gas generation phase.

scholarly journals Source rock geochemistry of shale samples from Ege-1 and Ege-2 wells, Niger Delta, Nigeria

2020 ◽  
Author(s):  
S. L. Fadiya ◽  
S. A. Adekola ◽  
B. M. Oyebamiji ◽  
O. T. Akinsanpe
Keyword(s):  
Source Rock ◽  
Niger Delta ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Early Maturity ◽  
Type Iii ◽  
Niger Delta Basin ◽  
Rock Eval

AbstractSelected shale samples within the middle Miocene Agbada Formation of Ege-1 and Ege-2 wells, Niger Delta Basin, Nigeria, were evaluated using total organic carbon content (TOC) and Rock–Eval pyrolysis examination with the aim of determining their hydrocarbon potential. The results obtained reveal TOC values varying from 1.64 to 2.77 wt% with an average value of 2.29 wt% for Ege-1 well, while Ege-2 well TOC values ranged from 1.27 to 3.28 wt% (average of 2.27 wt%) values which both fall above the minimum threshold (0.5%) for hydrocarbon generation potential in the Niger Delta. Rock–Eval pyrolysis data revealed that the shale source rock samples from Ege-1 well are characterized by Type II–Type III kerogens which are thermally mature to generate oil or gas/oil. The Ege-2 well pyrolysis result showed that some of the ditch cutting samples are comprised of Type II (oil prone) and Type III (gas-prone kerogen) which are thermally immature to marginal maturity (Tmax 346–439 °C). This study concludes that the shale intercalations between reservoir sands of the Agbada Formation are good source rocks in early maturity and also must have contributed to the vast petroleum reserve in the Niger Delta Basin because of the subsidence of the basin.

scholarly journals Evaluation of Hydrocarbon Generation Using Structural and Thermal Modeling in the Thrust Belt of Kuqa Foreland Basin, NW China

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-18
Author(s):  
Chengfu Lyu ◽  
Xixin Wang ◽  
Xuesong Lu ◽  
Qianshan Zhou ◽  
Ying Zhang ◽  
...  
Keyword(s):  
Source Rock ◽  
Oil And Gas ◽  
Thermal Evolution ◽  
Foreland Basin ◽  
Source Rocks ◽  
Mature Stage ◽  
Hydrocarbon Generation ◽  
Thrust Belt ◽  
Salt Layer ◽  
Kuqa Foreland Basin

The Kuqa Basin is a typical foreland basin in northwest China, characterized by compressive foreland fold-and-thrust belts and a regionally distributed huge salt layer. A large number of overthrust faults, fault-related folds, and salt-related structures are formed on the thrust belt due to strong compression and structural deformation, causing difficulty in simulation of the basin. In this study, modeling of the thermal history of the complicated compressional structural profiles in the Kuqa foreland basin was successfully conducted based on the advanced “Block” function introduced by the IES PetroMod software and the latest geological interpretation results. In contrast to methods used in previous studies, our method comprehensively evaluates the influence of overthrusting, a large thick salt layer with low thermal conductivity, fast deposition, or denudation on the thermal evolution history. The results demonstrate that the hydrocarbon generation center of the Kuqa foreland basin is in the deep layers of the Kelasu thrust belt and not in the Baicheng Sag center, which is buried the deepest. A surprising result was drawn about the center of hydrocarbon generation in the Kuqa foreland basin, which, although not the deepest in Baicheng Sag, is the deepest part of the Kelasu thrust Belt. In terms of the maturity of the source rock, there are obvious temporal and spatial differences between the different structural belts in the Kuqa foreland basin, such as the early maturation of source rocks and the curbing of uplift and hydrocarbon generation in the piedmont zone. In the Kelasu thrust belt, the source rock made an early development into the low mature-mature stage and subsequently rapidly grew into a high-over mature stage. In contrast, the source rock was immature at an early stage and subsequently grew into a low mature-mature stage in the Baicheng Sag–South slope belt. The time sequence of the thermal evolution of source rocks and structural trap formation and their matching determines the different accumulation processes and oil and gas compositions in the different structural belts of the Kuqa foreland basin. The matching of the multistage tectonic activity and hydrocarbon generation determines the characteristics of the multistage oil and gas accumulation, with the late accumulation being dominant. The effective stacking of the gas generation center, subsalt structural traps, reservoir facies of fine quality, and huge, thick salt caprocks creates uniquely favorable geological conditions for gas enrichment in the Kelasu foreland thrust belt.

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