Petroleum System Analysis Research Articles

Source rock characterisation of under-explored regions of Queensland

Historically, petroleum exploration in Queensland has focused on the Bowen-Surat and Cooper-Eromanga basins, with only cursory examination of other basins across the state. As part of the Queensland Industry Priorities Initiative, two projects (Round 1 and 2) were submitted to the Geological Survey of Queensland (GSQ) to examine the geochemical characteristics of potential petroleum source rocks throughout Queensland. The analysis conducted provides a better understanding of generative potential for petroleum, and predicts the timing, volume, composition, and physical state of hydrocarbons retained in and expelled from source rocks. It is an integral component to petroleum systems analysis used to identify the potential for undiscovered accumulations of petroleum from conventional and unconventional reservoirs. Of particular interest were the Georgina, Drummond, Eromanga, and Maryborough basins. Of these, the Georgina and Maryborough basins have known hydrocarbon shows identified through exploration drilling, though no commercial discoveries have yet been made. The Drummond Basin was targeted to identify a potential source for oil and gas shows encountered in drilling within the Galilee Basin. The Toolebuc Formation in the Eromanga Basin has been noted as having the potential for a shale oil play and this study is supporting further assessment to identify optimal areas for future exploration through predictive modelling. This report details the results from Round 1 of the study for samples taken from the Georgina Limestone and Scartwater, Ducabrook, Mount Hall, Toolebuc, and Maryborough formations, where limited analysis of source rock characteristics has historically been undertaken. Ninety-seven samples were chosen from nine wells and sent to Geos4 in Potsdam, Germany, for source rock analysis. All samples were screened for suitability of further analysis using Rock-Eval and TOC by LECO, with immature and organic-rich samples being preferentially selected for further testing. Screened samples were analysed using pyrolysis gas chromatography (n=27), thermovaporisation (n=23), bulk kinetics (n=5), compositional kinetics (n=4), late gas analysis (n=14), and biomarker and bulk isotope analysis (n=15). These results have been integrated with existing analyses to better understand the prospectivity of the under-explored basins of Queensland.

Petroleum system analysis of West Korea Bay Basin, North Korea

북한의 서한만 분지는 상당량의 석유가 발견된 것으로 알려지고 있으나, 석유탐사에 대한 정보가 많지 않기 때문에 석유 산출에 대해서 정확하게는 알 수가 없다. 그러나 서한만 분지에 대한 지질과 광역층서, 그리고 수집된 탐사와 시추정보를 바탕으로 하여, 석유 생성 및 이동·집적에 대한 석유시스템을 수치 모델링 방법에 의하여 분석하였다. 서한만 분지는 고생대 탄산염암과 선캠브리아기의 변성암을 기반암으로 하며, 중생대층과 신생대층이 중첩되어 두껍게 퇴적되어 있는 열개분지(rift basin)이다. 석유시스템 모델링 결과, 주요 근원암층인 상부 쥬라기층에서 생성된 석유와 가스는 근원암으로부터 배출되어, 이 근원암층 내의 사질암층 지역과, 상부 쥬라기층 하위에 존재하는 탄산염 기반암층으로 이동하는 것이 관찰된다. 이 모델링 결과와 기존의 시추정보를 종합하여 해석하면 다음과 같은 석유생성, 이동, 집적에 대한 석유시스템이 추정된다. 즉, 서한만 분지의 석유와 가스를 생성한 주요 근원암은 심호환경에서 퇴적된 후기 쥬라기의 셰일층이다. 서한만 분지발달 과정에서 장기간의 융기와 무퇴적 기간이 존재함에 따라 이 근원암층은 지속적으로 매몰이 진행되지 못하였고, 이에 따라 근원암층에서 석유와 가스가 생성은 되었으나 다량의 석유와 가스가 배출되지는 못하였다. 일부 배출된 석유와 가스는 상위의 하부 백악기층(Lower Cretaceous strata)과 제3기층으로 이동하였을 뿐만 아니라, 하위의 탄산염 기반암층으로도 이동한 것으로 추정된다. 서한만 분지에는 광역적인 덮개암층은 존재하지 않는다. 따라서 석유와 가스는 고생대, 중생대, 신생대층 각각의 퇴적층 내 암상변화와 관련된 층서트랩의 형태로 집적되어 있을 가능성이 많다. 이 연구는 제한된 정보와 자료를 바탕으로 수행된 석유시스템 분석이므로, 추후에도 서한만 분지에 대한 지속적인 정보와 자료의 확보가 요구되며, 이들 자료와 정보를 바탕으로 재해석이 필요하다.

詳細な石油システム解析から見えるノルウェー堆積盆地の石油ポテンシャル

詳細な石油システム解析から見えるノルウェー堆積盆地の石油ポテンシャル

The source of highly overmature solid bitumens in the Permian coral reef paleo-reservoirs of the Nanpanjiang Depression

Solid bitumens occur extensively in Permian coral reefs of the Nanpanjiang Depression. Both potential source rocks and solid bitumens in the study area are highly overmature and have similar bulk carbon isotope values. It is difficult to perform an oil–source rock correlation study in this area based on only regular molecular geochemical methods and bulk carbon isotope values. Thus the covalently bound biomarkers released from solid bitumens and source rock kerogens by catalytic hydropyrolysis (HyPy), together with the geological settings, were taken into account in this oil–source rock correlation study. The distribution characteristics of covalently bound biomarkers suggest that the major source rock of the Longlin paleo-reservoir (in the midwest of the depression) solid bitumen should be the Middle Devonian mudstone, whereas the source rock of the Ziyun paleo-reservoir (in the north of the depression) solid bitumen should be the Lower Permian source rock. However, solid bitumens in the Ceheng and Wangmo paleo-reservoirs (in the middle of the depression) may be mainly sourced from the Middle Devonian source rock, but partly from the Permian source rock. Our bitumen–source rock correlation results are also supported by the petroleum geological settings of the study area, which indicate that the filling of those paleo-reservoirs was controlled by the matching of hydrocarbon generation and trap formation. Basically, the timing of hydrocarbon generation of the Middle Devonian source rocks matches well with the formation of Permian coral reef traps in the middle and midwest portions of the depression, but it is earlier than the formation of the Permian coral reef trap in the north of the depression. We show that our oil–source rock correlation study based on covalently bound biomarkers can provide reliable information for petroleum system analysis when highly overmature strata in South China are involved.

MATURITY AND PETROLEUM SYSTEMS MODELLING IN THE OFFSHORE ZAMBEZI DELTA DEPRESSION AND ANGOCHE BASIN, NORTHERN MOZAMBIQUE

Petroleum systems analysis and maturity modelling is used to predict the timing and locations of hydrocarbon generation in the underexplored offshore Zambezi Delta depression and Angoche basin, northern Mozambique. Model inputs include available geological, geochemical and geophysical data. Based on recent plate‐tectonic reconstructions and regional correlations, the presence of Valanginian and Middle and/or Late Jurassic marine source rock is proposed in the study area.The stratigraphy of the Mozambique margin was interpreted along reflection seismic lines and tied to four wells in the Zambezi Delta depression. Thermal maturity was calibrated against measured vitrinite reflectance values from these four wells. Four 1‐D models with calibration data were constructed, together with another five without calibration data at pseudo‐well locations, and indicate the maturity of possible source rocks in the Zambezi Delta depressions and Angoche basin. Two 2‐D petroleum systems models, constrained by seismic reflection data, depict the burial history and maturity evolution of the Zambezi Delta basin. With the exception of the deeply‐buried centre of the Zambezi Delta depression where potential Jurassic and Lower Cretaceous source rocks were found to be overmature for both oil and gas, modelling showed that potential source rocks in the remaining parts of the study area are mature for hydrocarbon generation.In both the Zambezi Delta depression and Angoche basin, indications for natural gas may be explained by early maturation of oil‐prone source rocks and secondary oil cracking, which likely began in the Early Cretaceous. In distal parts of the Angoche basin, however, the proposed source rocks remain in the oil window.

Effect of Some Input Parameters on 3D Basin and Petroleum Systems Modelling: A Case Study of the Norwegian Section of the Northern North Sea

The objective of this study is to test the influence of some key input parameters in basin modelling and to evaluate the resultant effect of varying these parameters on the model. 3D basin modelling and petroleum system analysis of the northern North Sea has been carried out using the PETROMOD software. The model was calibrated using well 34/8-7 in the Visund field. Different input parameters such as heat flow, source rock properties, fault properties, paleo water depth, source rock kinetics, migration methods and different erosion scenarios have been varied and their effects on the model assessed. The effect of the various input parameters has been assessed in terms of hydrocarbon volumes in the Kvitebjorn and Visund fields, source rock maturity, transformation ratios, hydrocarbon saturations and the time hydrocarbon generation began in the Draupne and Heather Formation source rocks. Increase in heat flow increases source rock maturity, the start of hydrocarbon generation, transformation ratios and results in the generation of a lot more gas than oil. Hydrocarbon generation starts at shallower depths with higher heat flow. Increasing Total Organic Content (TOC) and Hydrogen Index (HI) generally results in increase in the volume of hydrocarbons generated. The increase in HI, however, results in the generation of a lot more oil than gas. High TOC and HI also increase the hydrocarbon saturations in the source rock. Increasing Paleo Water Depth (PWD) has a marginal effect on the model. It increases the volume of oil and decreases the volume of gas marginally. Varying the PWD has no significant effect on source rock maturity, transformation ratios and hydrocarbon saturations. Opening the fault planes resulted in an increase in the volume of hydrocarbons generated. The increase was more evident in the volume of oil than gas. This increase in volumes is a consequence of additional migration pathways created by the faults. Varying the erosion thickness of the Draupne Formation did not have any effect on the model.

Neural networks and their derivatives for history matching and reservoir optimization problems

In geosciences, complex forward problems met in geophysics, petroleum system analysis, and reservoir engineering problems often require replacing these forward problems by proxies, and these proxies are used for optimizations problems. For instance, history matching of observed field data requires a so large number of reservoir simulation runs (especially when using geostatistical geological models) that it is often impossible to use the full reservoir simulator. Therefore, several techniques have been proposed to mimic the reservoir simulations using proxies. Due to the use of experimental approach, most authors propose to use second-order polynomials. In this paper, we demonstrate that (1) neural networks can also be second-order polynomials. Therefore, the use of a neural network as a proxy is much more flexible and adaptable to the nonlinearity of the problem to be solved; (2) first-order and second-order derivatives of the neural network can be obtained providing gradients and Hessian for optimizers. For inverse problems met in seismic inversion, well by well production data, optimal well locations, source rock generation, etc., most of the time, gradient methods are used for finding an optimal solution. The paper will describe how to calculate these gradients from a neural network built as a proxy. When needed, the Hessian can also be obtained from the neural network approach. On a real case study, the ability of neural networks to reproduce complex phenomena (water cuts, production rates, etc.) is shown. Comparisons with second polynomials (and kriging methods) will be done demonstrating the superiority of the neural network approach as soon as nonlinearity behaviors are present in the responses of the simulator. The gradients and the Hessian of the neural network will be compared to those of the real response function.

The Mishrif, Yamama, and Nahr Umr reservoirs petroleum system analysis, Nasiriya oilfield, Southern Iraq

Forty rock samples were taken from cores and cuttings, and five oil samples were taken from Mishrif, Nahr Umr, and Yamama formations in the Nasiriya oilfield wells, of longitudinal, asymmetrical anticline structure, of about 34 km length and 13 km width located at the unstable plat form, Mesopotamian basin zone. Three major oil reservoirs in the Nasiriya oilfield: (1) Late Cenomanian–Early Turonian Mishrif Formation with reserved oil approximately 1,009 million tons show measured porosities up to 40 % and the oils are aromatic, medium gravity, high sulfur content, and interpreted as being sourced from: type II/III carbonate rocks interbedded and deposited in a reducing marine environment with high salinity based on biomarkers and isotopic analysis; Middle–Upper Jurassic age is based on sterane ratios analysis of isoprenoids and isotopes, and thermally mature source rocks. (2) The reservoirs of the Albian Nahr Umr of approximately 68 million tons reserved oil show measured porosities up to 23 %. (3) Late Berriasian–Early Valanginian Yamama formations of 275 million tons reserved oil measured porosities up to 28.8 %. The Nahr Umr and Yamama reservoirs oils are saturated, light to medium API gravity, low to medium sulfur content which are usually derived from marine shale and carbonate source rocks (containing type II kerogen). The upper seal is the Middle Miocene anhydrites of the Lower Fars Formation and the lower regional seal is Upper Jurassic Gotnia anhydrites. Source rock geochemical analysis suggests for all Cretaceous source rocks samples, immature to mature, and shows that the Sulaiy and Yamama formations to be of good quality source rock with high total organic carbon (up to 8 wt% TOC). The Lower Cretaceous source rocks were deposited in a suboxic–anoxic basin and show good hydrogen indices, and are likely to have charged the reservoirs with low amounts of hydrocarbons, during the Miocene. The most likely source rock for the Mishrif-, Yamama-, and Nahr Umr-reservoired oils are the Middle–Upper Jurassic source rock. The migration from the source rock is likely to be largely vertical and possibly along faults before reaching highly permeable reservoirs of the reservoir formations. Structural traps in the Mishrif, Nahr Umr, and Yamama formation reservoirs are likely to have formed in the Late Cretaceous.

2D Basin Modelling and Petroleum System Analysis of the Triassic Play in the Hammerfest Basin of the Norwegian Barents Sea

This study seeks to demonstrate the methodology used in 2D basin modelling, enhance the understanding of the Triassic play in the Hammerfest Basin and to show how basin modelling can be used to reduce exploration risk and improve exploration success using the Triassic play in the Hammerfest Basin in the Norwegian Barents Sea as a case study. 2D basin modelling has been done for the Triassic play in the Hammerfest Basin using Petromod software. The play consists of a source rock (Fruholmen formation) of Triassic age, a reservoir (Sto formation) of Middle to Lower Jurassic age and seals of Cretaceous and Upper Jurassic age. Three episodes of erosion (uplifts) in the Late Cretaceous, Paleogene and Paleogene-Neogene have occurred in the basin breaching the integrity of the seal and allowing the escape of hydrocarbons from the trap in some places. These episodes of erosion have increased exploration risks in the Hammerfest Basin and Barents Sea in general. Migration from the source rock into the trap is mainly upwards vertical migration. However, in areas where the hydrocarbons have escaped through the faults at the boundaries of the basin, migration in the layers above the trap is mainly lateral. The hydrocarbons generated are both gas and oil but are predominantly gas. The Upper Jurassic Hekkingen formation in the Barents Sea is a good source rock rich in organic matter with high values of hydrogen index and total organic matter but it doesn't seem to be matured in the Hammerfest Basin.

Petroleum system analysis of the Khatatba Formation in the Shoushan Basin, north Western Desert, Egypt

The Middle Jurassic Khatatba Formation is an attractive petroleum exploration target in the Shoushan Basin, north Western Desert, Egypt. However, the Khatatba petroleum system with its essential elements and processes has not been assigned yet. This study throws the lights on the complete Khatatba petroleum system in the Shoushan Basin which has been evaluated and collectively named the Khatatba-Khatatba (!) petroleum system. To evaluate the remaining hydrocarbon potential of the Khatatba system, its essential elements were studied, in order to determine the timing of hydrocarbon generation, migration and accumulation. Systematic analysis of the petroleum system of the Khatatba Formation has identified that coaly shales and organic-rich shales are the most important source rocks. These sediments are characterised by high total organic matter content and have good to excellent hydrocarbon generative potential. Kerogen is predominantly types II–III with type III kerogen. The Khatatba source rocks are mature and, at the present time, are within the peak of the oil window with vitrinite reflectance values in the range of 0.81 to 1.08 % Ro. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in the Khatatba sandstones which are characterised by fine to coarse grain size, moderate to well sorted. It has good quality reservoir with relatively high porosity and permeability values ranging from 1 to 17 % and 0.05–1,000 mD, respectively. Modelling results indicated that hydrocarbon generation from the Khatatba source rocks began in the Late Cretaceous time and peak of hydrocarbon generation occurred during the end Tertiary time (Neogene). Hydrocarbon primarily migrated from the source rock via fractured pathways created by abnormally high pore pressures resulting from hydrocarbon generation. Hydrocarbon secondarily migrated from active Khatatba source rocks to traps side via vertical migration pathways through faults resulting from Tertiary tectonics during period from end Oligocene to Middle Miocene times.

Petroleum system analysis of the Hammerfest Basin (southwestern Barents Sea): Comparison of basin modelling and geochemical data

Exploration in the Hammerfest Basin, southwestern Barents Sea, has proven several petroleum systems and plays with the presence of multiple source rocks of mainly Jurassic and Triassic age. To date several fields and discoveries have been found and are described to mainly contain gaseous hydrocarbons with the presence, in some cases, of an oil leg.Our 3D Hammerfest Basin model shows that the Jurassic Hekkingen Formation and the Triassic Snadd and Kobbe formations reached high maturity levels (gas window) in the western and the northwestern margin. At the same time, this model reproduces the main hydrocarbon accumulations that have been found in the basin. An analysis of the volumetrics and the proportion of oil and gas contributions to each field and discovery, suggests that the gas contribution stems mainly from Triassic source rocks, while the oil phases contain variable proportions from the Jurassic Hekkingen Formation and Triassic source rocks.Gas isotope and maturity related biomarker ratios confirm the maturity trends derived from the basin modelling results. Light hydrocarbons indicate the influence of secondary processes (biodegradation and long distance migration) in the petroleum from the Goliat field and the Tornerose discovery. Age related biomarker ratios such as the ETR (extended tricyclic terpane ratio) and the C28/C29 steranes ratio did not provide a clear separation when evaluating a contribution from Jurassic vs. Triassic source rocks.

Seismic facies analyses as aid in regional gas hydrate assessments. Part-II: Prediction of reservoir properties, gas hydrate petroleum system analysis, and Monte Carlo simulation

A new strategy to assess occurrences of marine gas hydrate has been implemented for the study area of the Ulleung Basin, East Sea, where two comprehensive gas hydrate drilling programs completed logging and coring at 18 sites. In this study we introduce multi-attribute analyses using five drill sites along a regional 2D seismic line to predict physical properties of P-wave velocity, density, and porosity required for gas hydrate saturation calculations. The five well-sites allow a reasonable cross-validation of the final multi-attribute-based prediction and to derive statistical parameters used in a Monte Carlo simulation of total gas hydrate volume in the study area. A similar analysis was completed for a 3D seismic volume around Site UBGH1-4. The crucial boundaries of the top of gas hydrate occurrence zone (TGHOZ) and base of the gas hydrate stability zone (BGHSZ) that are part of the gas hydrate petroleum system were calculated using constraints on geothermal gradient, pore-fluid salinity, type of hydrocarbon gases present, sedimentation rates, and total organic carbon content based on results from the two drilling expeditions carried out in the Ulleung Basin as well as other regional studies. Gas hydrate saturations were determined following the effective medium theory and using the sedimentological data obtained at the drill sites to define required mineral compositions. Seismic facies classification allowed the definition of occurrence of certain sediment types along the seismic data used in this study, and physical properties from the multi-attribute analyses and mineral compositions were assigned to each facies class. Statistical parameters of mean and standard deviation were estimated for each input parameter (P-wave velocity, bulk density, mineral compositions, grain density, density-porosity, TGHOZ, BGHSZ) in the gas hydrate saturation calculations based on individual uncertainties in the measurements. In the final step, a Monte Carlo simulation is used to calculate the total amount of gas hydrate (in m3) present in the study region for the two example data set of a 2D seismic line and one 3D seismic volume. The Monte Carlo simulation draws on the various statistical distributions of the input parameters and we have implemented 150,000 simulation runs in this study. The final histogram distributions of total volume of gas hydrate (in m3) allow determination of the mean, median, and mode values, as well as the 95% and 5% probability thresholds for gas hydrate volumes being present in the two study regions, though they are not meant as estimates of possible commercial amounts of gas associated with gas hydrates in the Ulleung Basin.

Basin-scale fluid flow in the Gippsland Basin: implications for geological carbon storage

Petroleum systems analysis has been carried out to better understand the geological CO2 storage potential of the Gippsland Basin. From a regional perspective, the hydrocarbon migration architecture of the basin is interpreted to be dominated by two highly connected, filled-to-spill, hydrocarbon fairways; the northern (gas-dominated) and southern (oil-dominated) fill-spill chains, forming a convergent system that extends onshore along the Golden Beach Fill-Spill Chain (GBFSC). A separate oil-dominated Fill-Spill Chain, the Dolphin-Perch Fill-Spill Chain (DPFSC), is identified offshore to the southwest. Two broad flanking provinces, the Northerly Migration Province (NMP) and Southerly Migration Province (SMP), are also identified. Both provinces have broadly ramp-like geometries and relatively low dips. Migration across these provinces is not focused, and hence multiple pathways are present across a wide area. An understanding of the hydrocarbon systems in the basin can be used for characterising the potential for CO2 storage. Previous studies have shown that the top seal potential of the offshore Gippsland Basin is suited to geological carbon storage and that large areas are prospective as storage regions. However, the linked nature of the fluid flow systems and the focused fluid flow fairways between areas of high storage potential and leaky systems onshore will require both a good regional geological understanding and informed resource management.

The Upper Jurassic–Cretaceous petroleum system of southern Iraq: A 3-D basin modelling study

ABSTRACT A 3-D basin model of the southern Mesopotamian Basin, southern Iraq, was built in order to quantify key aspects of the petroleum system. The model is based on detailed seismic interpretation and organic geochemical data, both for source rocks and oils. Bulk kinetic analysis for three source rock samples was used to quantify petroleum generation characteristics and to estimate the temperature and timing of petroleum generation. These analyses indicate that petroleum generation from the Yamama source rock (one of the main source rocks in the study area) starts at relatively low temperatures of 70–80°C, which is typical for Type II-S kerogen at low to moderate heating rates typical of sedimentary basins. Petroleum system analysis was achieved using the results from 1-D, 2-D, and 3-D basin modelling, the latter being the major focus of this study. The 1-D model reveals that the Upper Jurassic–Lower Cretaceous sediments are now within the oil window, whereas the formations that overlie the Yamama Formation are still immature in the entire study area. Present-day temperature reflects the maximum temperature of the sedimentary sequence, which indicates that no strong regional uplift affected the sedimentary rocks in the past. The 3-D model results indicate that oil generation in the Yamama source rock already commenced in the Cretaceous. At some locations of the basin this source rock reaches a present-day maximum temperature of 140–150°C. The most common migration pathways are in the vertical direction, i.e. direct migration upward from the source rock to the reservoir. This is partly related to the fact that the Lower Cretaceous reservoir horizons in southern Iraq directly overlay the source rock.

Petroleum system analysis of the Hunton Group in West Edmond field, Oklahoma

West Edmond field, located in central Oklahoma, is one of the largest oil accumulations in the Silurian–Devonian Hunton Group in this part of the Anadarko Basin. Production from all stratigraphic units in the field exceeds 170 million barrels of oil (MMBO) and 400 billion cubic feet of gas (BCFG), of which approximately 60 MMBO and 100 BCFG have been produced from the Hunton Group. Oil and gas are stratigraphically trapped to the east against the Nemaha uplift, to the north by a regional wedge-out of Hunton strata, and by intraformational diagenetic traps. Hunton Group reservoirs are the Bois d'Arc and Frisco Limestones, with lesser production from the Chimneyhill subgroup, Haragan Shale, and Henryhouse Formation. Hunton Group cores from three wells that were examined petrographically indicate that complex diagenetic relations influence permeability and reservoir quality. Greatest porosity and permeability are associated with secondary dissolution in packstones and grainstones, forming hydrocarbon reservoirs. The overlying Devonian–Mississippian Woodford Shale is the major petroleum source rock for the Hunton Group in the field, based on one-dimensional and four-dimensional petroleum system models that were calibrated to well temperature and Woodford Shale vitrinite reflectance data. The source rock is marginally mature to mature for oil generation in the area of the West Edmond field, and migration of Woodford oil and gas from deeper parts of the basin also contributed to hydrocarbon accumulation.

Geological risk evaluation using the Support Vector Machine with examples from the late Triassic-early Jurassic structural play in western Sverdrup Basin, Canadian Arctic Archipelago

Abstract A meaningful exploration decision depends not only on a reliable estimate of resource potential, but also on a robust geological risk evaluation of the exploration targets. We propose a Support Vector Machine approach for geological risk evaluation of petroleum occurrence in a petroleum play. The resulting risk map can be used to highlight the geographic locations of potential undiscovered petroleum resources and help visualize regional exploration risk. Treating risk evaluation as a two-category classification with uncertainty, this method integrates all available data and geoscience information from regional study and petroleum system analysis to interrogate and evaluate exploration drilling results. From this it makes inference on the likelihood of petroleum occurrence for untested exploration targets in a petroleum exploration play. Together with estimated sizes of remaining untested prospects, it provides a risked resource map for ranking exploration opportunities and helping to make business decisions affecting exploration strategy. This approach can also be used in evaluation of unconventional resource plays to highlight ‘sweet spots’ and estimate ‘dry well’ risk. The proposed method and workflow are illustrated using an example from the late Triassic–early Jurassic structural play of the Heiberg Group in the western Sverdrup Basin, Canadian Arctic Archipelago.

11892 Heterogeneous gravity data combination for geophysical exploration research: Applications for basin and petroleum system analysis in the Arabian Peninsula

The GOCE satellite gravity emission was launched in 2009 to measure the gravity gradient with high accuracy and spatial resolution. GOCE gravity data may improve the understanding and modeling of the Earth's interior and its dynamic processes, contributing to new insights into the geodynamics associated with the lithosphere, mantle composition and rheology, uplift and subduction processes. However, to achieve this challenging target, GOCE should be used in combination with additional data sources, such as in-situ gravimetric, magnetic, and seismic data sets

泥質岩圧密モデルから石油システム解析へ

泥質岩圧密モデルから石油システム解析へ

Comment to “Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential” [Mar. Pet. Geol. 26 (2009) 1656–1676

Comment to “Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential” [Mar. Pet. Geol. 26 (2009) 1656–1676

Reply to the comment of Büyüksaraç and Nazan Yalcin Erik ‘Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential’ [Mar. Pet. Geol. 26 (2009) 1656–1676

Reply to the comment of Büyüksaraç and Nazan Yalcin Erik ‘Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential’ [Mar. Pet. Geol. 26 (2009) 1656–1676