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Abstract The reduction of pore pressure during reservoir production alters the initial stress state within the reservoir and the surrounding rocks. This stress variation is responsible for many problems encountered during production (e.g. fault reactivation, casing deformation). In this investigation, a newly designed True Triaxial Stress Loading and Pore Pressure Applying Apparatus (TTSL-PPAA) was applied to study the coupling of pore pressure drawdown and reservoir stress changes under actual field conditions. The objective was to overcome the shortcomings of commonly employed depletion testing under conventional triaxial conditions, which assumes that both horizontal stress components are equal. The depletion simulations were performed by decreasing the pore pressure and under applying constant vertical and keeping zero horizontal strains, i.e. uniaxial strain boundary conditions. The results showed that both horizontal stresses decrease with a linear trend with pore pressure depletion. The reduction rates of minimum and maximum horizontal stresses, however, are not uniform. The rate of maximum horizontal stress reduction is higher than the minimum horizontal stress component. Moreover, the pore pressure/stress coupling intensity is dependent on the initial, pre-production, stress state. By increasing the initial vertical stress, and therefore, decreasing the ratios of horizontal to vertical stress, (referred to as K H = σ H /σ V and K h = σ h /σ V), the effect of pore pressure depletion on in situ stress components was decreased. The obtained test results imply that, in addition to stress magnitude changes, the stress regime might be locally changed by production due to pore pressure/stress coupling. Furthermore, the rock sample failure in some depletion tests indicates that the pore pressure/stress coupling can be used to describe the production induced seismicity reported in hydrocarbon reservoirs worldwide. Highlights • The paper describes the development of a new True Triaxial Stress Loading and Pore Pressure Applying Apparatus (TTSL-PPAA). • The TTSL-PPAA system is employed to demonstrate the depletion mechanisms associate with oil reservoirs. • The depletion simulations were conducted to show the coupled nature of pore pressure and in situ stress filed. • Due to pore pressure reduction both horizontal stress components start to decrease in a linear trend. [ABSTRACT FROM AUTHOR]

Fractured carbonate reservoirs constitute a considerable proportion of hydrocarbon reservoirs in the world. In these reservoirs, gravity drainage is one of the dominating oil producing mechanisms that controls oil production depending on the interactions between the upper and lower blocks. Nonetheless, few theoretical studies have investigated the modeling of the reinfiltration process between the blocks. In this study, first, the gravity drainage process is modelled for a 1-D single matrix block by considering gravity and capillary forces, then Laplace transformation is used to solve the governing partial differential equation related to a matrix block with appropriate initial and boundary conditions. Next, the obtained equations are extended to a stack of matrix blocks and the effect of the reinfiltration process is investigated afterward. The inlet oil flow rate from the upper boundary of the blocks is a function of time, and the lower boundary of the blocks is fully saturated with oil. At the initial condition, the matrix block is saturated with oil. Finally, based on the aforementioned saturation equations, oil production rate, cumulative production, gravity drainage mechanism and the effect of the reinfiltration process are studied. The presented analytical solution is compared with previous semi-analytical solutions (Firoozabadi and Ishimoto, 1994), finite difference and finite element numerical techniques. Traditional gravity drainage models do not consider the effect of matrix block size distribution on oil recovery. In this study, a gravity drainage model is proposed to evaluate the oil recovery factor that considers this factor. The solution to the uniform distribution can be extended to more general distributions. Regarding the fact that the strength of gravity drainage mechanism is related to block size, higher fracture intensity (smaller grid blocks) leads to a fairly small decrease in gravity drainage forces such that most of oil within the matrix block stays unchanged. The obtained results from this study show that higher fracture intensity (smaller block height) causes lower oil recovery from matrix in gas invaded zone. The results of analytical model were compared with previous analytical model and experimental data and reasonable match was obtained for predicting final oil recovery. [ABSTRACT FROM AUTHOR]

Multistage fracturing is widely used to improve gas production in tight hydrocarbon reservoirs. As a sequential process that interacts with pre-existing fractures, multistage fracturing must be properly addressed in numerical simulations, which are important in evaluating and optimising fracturing technology. The challenges of accurately representing the complex fracture structures and physical properties of naturally fractured reservoirs cause that the interaction between hydraulic and pre-existing fractures has not yet been resolved satisfactorily. In this study, we adopt an adaptive finite element-discrete element method to simulate the multistage fracturing of a naturally fractured reservoir by improving the mesh auto-refinement and identification of multiple fracture propagation. The numerical model considers interactions among hydraulic fractures, pre-existing fractures, and microscale pores, and integrates the nonlinear Carter leak-off criterion to describe fluid leak-off and hydromechanical coupling effects during multistage fracturing. The proppant transport equation for idealised parallel plate flow in fractures is introduced, and Darcy's law is adopted to analyse the seepage flow in the fracture network and determine the gas recovery. The fracture network and consequent fluid flow induced by the hydrofracturing of unfractured and naturally fractured models are compared to assess the influence of pre-existing fractures on multistage fracturing behaviour and gas production. [ABSTRACT FROM AUTHOR]

Abu Roach "E" member is of an important hydrocarbon reservoir-producing horizon in the Abu Gharadig Field (north Western Desert, Egypt). This study is used to build facies analysis and depositional environments model for the Upper Unit of the Abu Roash "E" member in Abu Gharadig Field. This target has been achieved throughout the sedimentological, wire line logs, lithostratigraphic and biostratigraphic analyses of more than 528 feet cores. The high-resolution biostratigraphic analysis provides a calibration for the paleo-bathymetry and depositional environmental interpretations. Biozonation and lithostratigraphic markers are used to constrain stratigraphic correlation. Integration between the core description and petorographic microfacies analysis by microscope examination provide an excellent indication for the rock types and depositional environments. Five depositional facies types are detected including carbonate inner ramp, tidal flats, tidal channels, supra-tidal and tide dominated delta facies. This model helps in the understanding of the Upper Unit of Abu Roash "E" member reservoir distribution as well as lateral and vertical facies changes that contribute to the development strategy for the remaining hydrocarbon reserves for this important oil reservoir. [ABSTRACT FROM AUTHOR]

Three rounds of exploration in Marsel, Kazakhstan show that the area has good petroleum geological conditions; however, the exploration degree is low and the resource potential is unclear. The total organic carbon ( TOC ) content is the criteria for effective source rocks and is also the key parameter to calculate the amount of resources; while previous evaluations of the effective source rocks and calculated amounts of resources were based on residual TOC , which gradually decreases with mass hydrocarbon expulsion; therefore, this will inevitably produce errors. For greater accuracy, the TOC recovery coefficient formula was used to recover the residual TOC in Marsel; then, the criteria of the effective source rocks were revised to calculate the Carboniferous and Devonian resources in Marsel. The results are as follows: for the source rocks in Marsel, the TOC recovery coefficient of the Carboniferous source rocks is approximately 1.6, while that for the Devonian is approximately 2.0; the revised lower limit of TOC for the effective source rocks is 0.3% and 0.25% for the Carboniferous and Devonian, respectively; after TOC recovery, the total amount of hydrocarbon expulsion is 26.7 × 10 12 m 3 , the total amount of recoverable resources is 2.62–5.10 × 10 12 m 3 , and the mean is 3.79 × 10 12 m 3 for the main source rocks. The effective source rocks evaluated based on the recovered TOC and the latter resources could reflect the quantity of source rocks and actual resource potential of Marsel more accurately. This has certain significance for the exploration of areas that have low levels of exploration with an unclear understanding of the resource potential as well as a high degree of thermal evolution and a low quantity of residual TOC . [ABSTRACT FROM AUTHOR]

In the petroleum industry, water-and-gas breakthrough in hydrocarbon reservoirs is a common issue that eventually leads to uneconomic production. To extend the economic production lifetime, inflow-control devices (ICDs) are designed to delay the water-and-gas breakthrough. Because the lifetime of a hydrocarbon reservoir commonly exceeds 20 years and it is a harsh environment, the reliability of the ICDs is vital. With computational fluid dynamics (CFD), an inclined nozzle-based ICD is characterized in terms of the Reynolds number, discharge coefficient, and geometric variations. The analysis shows that especially the nozzle edges affect the ICD flow characteristics. To apply the results, an equation for the discharge coefficient is proposed. The Lagrangian particle approach is used to further investigate the ICD. This allows for erosion modeling by injecting sand particles into the system. By altering the geometry and modeling several scenarios while analyzing the erosion in the nozzles and at the nozzle edges, an optimized design for incompressible media is found. With a filleted design and an erosion-resistant material, the mean erosion rate in the nozzles may be reduced by a factor of more than 2,500. [ABSTRACT FROM AUTHOR]

The alteration of wettability can be a key mechanism for additional oil production from hydrocarbon reservoirs worldwide. This paper models thermally-induced wettability alteration from hot-water imbibition in naturally fractured reservoirs (NFRs). Hot-water (or steam) enhanced oil recovery (EOR) in fractured reservoirs can lead to increased oil recovery by enhancing water imbibition into matrix blocks, rendering the formation more water-wet. This will increase recovery as a result of decreased oil-water interfacial tension and reduced residual oil saturation. Modeling and evaluating production mechanisms in such a process in NFRs requires an understanding of multiphase flow parameters. In this work, numerical simulation codes with finite-difference formulations were developed to couple fluid flow and heat transfer for 1D and 2D flow geometries in spontaneous imbibition. This paper examines the effect of elevated temperature on wettability by considering various initial and boundary conditions. This approach results in more accurate simulation results as the relative permeability and capillary pressure curves are updated at each time step and for each grid (or each rock-type). The results from this study confirmed: a) the rate of recovery in co-current is generally higher than that in counter-current imbibition in a hot-water imbibition process, b) changing the wetting state in matrix from intermediate- or oil-wet to more water-wet proved to increase the ultimate recovery by reducing the residual oil saturation, c) updating the k r and P c curves vs. temperature in simulating a hot-water injection process in NFRs can be more accurate than the commercial simulators where the relative permeability and capillary pressure curves are updated based on solely their end-points. [ABSTRACT FROM AUTHOR]

The tendency to identify leaking zones is essential tool in trap assessment. Faults play an important role in creation of hydrocarbon traps. For volumetric analysis of a field to be meaningful, it is essential to analyze the faults contributing to the accumulation of hydrocarbons in a trap. These faults may be sealing or act as conduit to fluid flow. Analysis of trap is therefore carried out with the aim to reduce the uncertainties associated with hydrocarbon exploration and exploitation in Niger-Delta using "Covenant" field as a case study. The aim of the study is achieved using three dimensional seismic and well log data. Three reservoirs were mapped on the field while the fault supporting the identified trap was analyzed via throw, shale volume, shale gouge ratio, and hydrocarbon column heights attributes. The volume of shale model shows the presence of shale and sandstone formations in the fault plane. The fault-horizon's intersection (throw) model reveals that the horizons were not too deviated from where the maximum fault's displacement was noticed. The estimated shale gouge ratio of the fault on the analyzed trap reveals that the shallow sand horizon is supported by moderate sealing plane while that of mid and deep sand horizons are supported by proper sealing fault plane. The hydrocarbon column height model reveals a column height of 120m supports the shallow sand horizon while column heights È 180m support the mid and deep sand horizons respectively. It was inferred that despite the three horizons are supported by sealing fault zone, leakage still occurs at shallow sand horizon which correspond to a moderately sealed plane from SGR. [ABSTRACT FROM AUTHOR]

The Siberian Traps Large igneous province was a key player in the end-Permian extinction and climatic change due to degassing from lavas and heated sedimentary rocks. Although the specific degassing scenarios from the province are debated, this implies that gas release on a timescale tuned to the cooling of lava flows and subvolcanic intrusions (i.e. decades to centuries) must have been sufficient to affect the atmospheric chemistry. Here we test this assumption by using simple box model calculations to constrain century-scale degassing of CO 2 and CH 4 from high-end volumes of individual lava flows and sills from the Siberian Traps. The model includes gas fluxes of CH 4 and CO 2 , their atmospheric lifetimes and radiative forcing, as well as the climate sensitivity in a global average climate system calibrated to end-Permian time. The fluxes are estimated based on lava degassing and contact aureole volumes and devolatilization during the first 100 years following emplacement. We test the sensitivity to extreme emissions of up to 25 GtC/yr, CH 4 fractions from 0 to 100%, wide ranges of climate sensitivities (1.5–6.0 °C for CO 2 doubling), pre-event concentrations, and atmospheric lifetimes. We find that the global annual mean temperature perturbation is 7.0 °C in our baseline case using a 10 GtC/yr emission and a 60% CH 4 fraction, assuming 4.5 °C as the climate sensitivity. Even for low emission scenarios (0.7–1.2 GtC/yr), the temperature response is ~ 1.5 °C. We conclude that sporadic individual large-scale volcanic events in Large igneous provinces have the potential to cause a strong global warming on very short timescales. In addition to the emission strength, the CH 4 fraction and the climate sensitivity have the strongest impact on the century-scale temperature perturbation. [ABSTRACT FROM AUTHOR]

The frequency-dependent seismic anomalies related to hydrocarbon reservoirs have lately attracted wide interest. The diffusive-viscous model was proposed to explain these anomalies. When an incident diffusive-viscous wave strikes a boundary between two different media, it is reflected and transmitted. The equation for the reflection coefficient is quite complex and laborious, so it does not provide an intuitive understanding of how different amplitude relates to the parameters of the media and how variation of a particular parameter affects the reflection coefficient. In this paper, we firstly derive a two-term (intercept-gradient) and three-term (intercept-gradient-curvature) approximation to the reflection coefficient of the plane diffusive-viscous wave without any assumptions. Then, we study the limitations of the obtained approximations by comparing the approximate value of the reflection coefficient with its exact value. Our results show that the two approximations match well with the exact solutions within the incident angle of 35°. Finally, we analyze the effects of diffusive and viscous attenuation parameters, velocity and density in the diffusive-viscous wave equation on the intercept, gradient and curvature terms in the approximations. The results show that the diffusive attenuation parameter has a big impact on them, while the viscous attenuation parameter is insensitive to them; the velocity and density have a significant influence on the normal reflections and they distinctly affect the intercept, gradient and curvature term at lower acoustic impedance. [ABSTRACT FROM AUTHOR]

Differences between the Cenozoic and pre-Cenozoic strata and structures in the middlesouth South Yellow Sea are analyzed using high-resolution airborne gravity data combined with data from offshore wells, seismic exploration and the regional geological background, using forward and inverse methods. We discuss why hydrocarbon exploration has so far failed in the South Yellow Sea, and put forward alternative future exploration plans. The results show that there are thick Cenozoic strata over Jurassic-Cretaceous continental strata in the southern basin of the South Yellow Sea, contrasted with thick Mid-Paleozoic marine strata preserved in the middle uplift area. In the mid-southern South Yellow Sea, airborne Bouguer gravity anomalies are fragmentized with scattered local anomalies. Many tensile normal faults and minor fault blocks occur in the Cenozoic strata. In contrast, reverse faults and nappe structures are found in pre-Cenozoic strata. The essential reasons for the lack of a breakthrough in hydrocarbon exploration are the complexity of geological structures, hydrocarbon accumulation environments, seismic-geologic conditions, and the difficulty of interpreting and understanding these features, rather than an imbalance of exploration framework. Hydrocarbon exploration should be targeted at Mid-Cenozoic continental strata, especially of Paleogene age, in the middle to southern parts of the South Yellow Sea. Special attention should be paid to the favorable structural belts SYI1, SYI2, SYI3 and SYI4 in the southern basin of the South Yellow Sea, where detailed seismic exploration or drilling should be carried out. Attention should also be given to Mid-Paleozoic marine strata in the middle uplift area of the South Yellow Sea. Key strategies that could lead to a hydrocarbon exploration breakthrough are improving exploration resolution, conducting detailed studies of fine structures, and accurately locating minor structures. [ABSTRACT FROM AUTHOR]

To date, most condensates and gases found in the Hammerfest Basin exist in distal, central basin settings, in traps with tight cap rocks of class 1 traps, whereas low-gas-oil-ratio (GOR) oils occur systematically in proximal basin settings, where cap rocks of class 3 traps prevail. Multiple fill-spill events resulted in the redistribution of oils toward structurally higher basin margins. In a systematic evaluation of light hydrocarbon parameters from condensates and oils, it was found that oils in general exhibit more traceable alteration effects than do condensates. Whereas 75% of condensate and 13.3% of oil samples are fractionated, 6.25% and 10%, respectively, show signs of biodegradation. Long-distance migration is indicated for 12.5% of condensate and 50% of oil samples. In addition, clear evidence is shown for the mixing of recently migrated high-GOR petroleum phases with older, low-GOR paleo oils. In general, variation in source-specific parameters is surprisingly less pronounced. Decreasing thermal maturity of entrapped petroleum from the eastern part of the Tromso Basin toward the Masoy-Nysleppen Fault Complex is observed, whereas high maturities are shown for the Nordkapp Basin and the Finnmark Platform in the eastern part of the study area. Low-to-medium maturities are recorded for oils from the basin margins of the Hammerfest Basin. Alterations in the composition of the petroleums by physiochemical processes and distribution patterns of the petroleums are closely associated with uplift and erosion. [ABSTRACT FROM AUTHOR]

The Siberian Traps large igneous province was formed during the end-Permian, about 252 Ma ago. Basaltic melt was injected into the organic and salt rich Tunguska sedimentary basin, forming interconnected sill complexes and associated hydrothermal vent complexes. Thick deposits of basaltic tuff and tephra covered the paleosurface before the onset of flood volcanism, commonly taken as direct evidence for the explosive nature of the initial phase of volcanism. The field work in this study revealed that tuffs are virtually absent along a 150 km long transect along the Dyupkun lake and Kureika river, even though tuff is shown on available geological maps. Towards the south and west, the transition between the end-Permian sediments and the flood basalts is either characterized by thin (2–5 m) to no tephra deposits (Khantaika area), hyaloclastites and associated lake-deposited tephra (Kureika area), or massive tephra deposits from local eruptive centers (Severnaya area). The new results can be put into the context of other studies about volcanic tuff horizons in Siberia, and questions the notion of province-scale explosive volcanism in Siberia during the onset of flood volcanism. Moreover, the main thicknesses of explosive tuff deposits, up to 700 m, are located in the central and southern parts of the province where the LIP erupted through thick Cambrian salt and carbonate sequences. Since numerous phreatomagmatic pipes are present in these areas, we suggest a causal relationship between deep magma–sediment interactions, explosive eruptions and the resulting environmental stress that initiated the end-Permian mass extinction. [ABSTRACT FROM AUTHOR]

Hydrocarbon reservoir pressure depletion leads to stress changes inside the reservoir and ground deformation which is registered at the surface as subsidence. As reservoirs are often overlain by layers of rocksalt (or other evaporites), which are materials that flow so as to relax stresses inside them, there is the potential for time-varying surface subsidence. This work focuses on understanding the macroscopic mechanisms that lead to rocksalt flow-induced ground displacements. A Finite Element Model is used for this purpose in which the rocksalt layer is represented by a viscoelastic Maxwell material. Two distinct mechanisms that lead to displacement are observed. These are active during different stages of the deformation and have different timescales associated with them. An important observation is that the timescale for deformation that is measured at the ground surface is not equal to the timescale for deformation of a viscoelastic material element, but can be many times larger than that. The sensitivity of the response to the thickness and location of the rocksalt layer is also presented. Conclusions are drawn which allow for the relative importance of the presence of the rocksalt layer to be assessed and for a framework for understanding time-dependent subsidence above producing hydrocarbon reservoirs to be developed. Finally the changes in stress distribution around a producing reservoir are also briefly discussed. [ABSTRACT FROM AUTHOR]

This paper reviews the hydrocarbon-retaining properties of overpressured reservoirs and discusses the mechanisms for petroleum accumulation, preservation and loss in overpressured reservoirs, and the factors controlling hydrocarbon column heights in overpressured traps. Four types of overpressured traps (filled, underfilled, unfilled, and drained) are recognized. The diversities in petroleum-bearing properties reflect the complexities of petroleum accumulation and leakage in overpressured reservoirs. Forced top seal fracturing, frictional failure along preexisting faults, and capillary leakage are the major mechanisms for petroleum loss from overpressured reservoirs. The hydrocarbon retention capacities of overpressured traps are controlled by three groups of factors: (1) factors related to minimum horizontal stress (tectonic extension or compression, stress regimes, and basin scale and localized pressure-stress coupling); (2) factors related to the magnitudes of water-phase pressure relative to seal fracture pressure (the depth to trap crest, vertical and/or lateral overpressure transfer, mechanisms of overpressure generation); and (3) factors related to the geomechanical properties of top seals or sealing faults (the tensile strength and brittleness of the seals, the natures and structures of fault zones). Commercial petroleum accumulations may be preserved in reservoirs with pressure coefficients greater than 2.0 and pore pressure/vertical stress ratios greater than 0.9 (up to 0.97). The widely quoted assumption that the fracture pressure is 80%-90% of the overburden pressure and hydrofracturing occurs when the pore pressure reaches 85% of the overburden pressure significantly underestimates the maximum sustainable overpressures, and thus, potentially the hydrocarbon- retention capacities, especially in deeply buried traps. Lateral and/or vertical water-phase overpressure transfer from deeper successions plays an important role in the formation of unfilled and drained overpressured traps. Traps in hydrocarbon generation-induced overpressured systems have greater exploration potential than traps in disequilibrium compaction-induced overpressured systems with similar overpressure magnitude. [ABSTRACT FROM AUTHOR]

Spontaneous-potential (SP) log data from wells in the deep eastern Greater Green River Basin (GGRB) suggest that what appears to be overpressured pervasive gas at high saturation in Upper Cretaceous sandstones outside conventional fields is gassy water with gas present at uneconomically low saturation. Sandstones of the Lewis Shale and Mesaverde Group within conventional-trap fields in the deep eastern GGRB exhibit normal-SP deflections, indicating saline formation water with low formation-water resistivity (RW) that yields calculated water saturations (SW) less than 50%. However, in deep-basin areas outside conventional traps, these Upper Cretaceous sandstones generally exhibit reversed-SP signatures reflecting anomalously low-salinity formation water with anomalously high RW that yields calculated SW greater than 60%. Uneconomically low gas saturations are corroborated by lack of commercial gas production from reversed-SP sandstones despite (1) prominent gas shows during drilling, (2) significant overpressure, and (3) log-measured porosity and resistivity that often are indistinguishable from those observed with commercially productive normal-SP sandstones within conventional traps. Anomalously low-salinity water in deep-basin sandstones outside conventional traps is proposed to result from dilution of original saline formation water by fresh water expelled during smectite-clay conversion to illite with increasing temperature (burial depth). Low permeability of deep-basin sandstones retards escape of the added fresh water, which contributes to overpressure and to deceptively high formation resistivity. Although the upward transition to more saline formation water is gradational, mapped top of reversed SP cuts across stratigraphic boundaries, with relief exceeding 2000 ft (610 m). It is unclear whether regional continuous gas in reversed-SP sandstones has been at low saturation since the onset of gas migration or whether saturations were higher prior to the influx of fresh water. What is reasonably certain is that subsequent to gas migration, fresh-water influx in the deep basin regionally diluted original saline formation water outside conventional traps. Similar formation-water salinity of normal-SP sandstones of the Lewis Shale and Mesaverde Group within deep-basin conventional traps suggests that high-saturation gas and associated irreducible saline formation water in these fields are locked-in accumulations unaffected by subsequent fresh-water influx. [ABSTRACT FROM AUTHOR]

The Permian White Rim Sandstone is a partly exhumed, primary reservoir of the Tar Sand Triangle accumulation in southeastern Utah. In the Elaterite Basin (Canyonlands National Park and Glen Canyon National Recreation Area), the White Rim Sandstone is well exposed and varies in color from white to red, orange, and brown. Superimposed on eolian and marine deposits are three diagenetic facies that impart the coloration and are defined by iron oxide cement concentration as (1) bleached white (low iron), (2) diffuse (moderate iron), and (3) concretionary (concentrated iron). A yellow alteration aureole of bleaching extends up to 10 m (32 ft) into the underlying Organ Rock Shale and up to 20 m (65 ft) into the overlying Moenkopi Formation. These formations surround the White Rim reservoir as fine-grained seals. Field, petrographic, and geochemical analyses indicate that the White Rim Sandstone records three major diagenetic stages. (1) The reservoir underwent oxidation, which led to the precipitation of thin iron grain coatings. (2) Hydrocarbon migration through the reservoir removed early grain coatings and reprecipitated disseminated and concentrated pyrite cement. (3) The pyrite was later altered to hematite or goethite by oxidizing fluids. In conventional petroleum exploration, the timing of hydrocarbon migration is often difficult to resolve. This study utilizes the record of mobilized and reprecipitated iron as a tool to constrain interpretations of the timing of hydrocarbon migration relative to seal and trap emplacement. This study has broad application as an exploration tool for deciphering fluid flow in similar clastic reservoirs. [ABSTRACT FROM AUTHOR]

The Pleistocene Saturnia travertine (central Italy) represents a possible analog of the pre-salt continental carbonate reservoirs discovered in the Santos and other basins in the South Atlantic margin of Brazil. Two subhorizontal travertine tabular bodies, several tens of meters thick and extending over an area of 15 km² (5. 8 mi²), have been studied in two quarries. Facies variations and associated petrophysical properties were reconstructed applying a multidisciplinary approach. The Saturnia travertine, formed from a warm water spring, is composed of various stacked carbonate banks, separated by subaerial erosive phases and paleosols. The lacustrine tabular bodies, terraces, and sills are made of crystalline cmst, shrub, pisoid, paper-thin raft, coated bubble, reed, and lithoclast-breccia facies. The δ13C (from +4‰ to +8‰) supports an interpreted CO2 volcanic mantle source, whereas, the δ180 (from -9‰ to -5‰) is in agreement with warm meteoric waters. The 87Sr/86Sr ratio isotopic signature indicates a carbonate from dissolution of deep-seated carbonates. The facies reservoir properties were studied via porosity and permeability analysis of plugs, three-dimensional x-ray computer tomography, as well as image analysis on microscale under thin section and macroscale on large rock slabs to define various porosity indices. A strong heterogeneity of the petrophysical properties and variable connectivity were observed (porosity from 4% to 30% and permeability up to hundreds of md), but no compartmentalization of the carbonate bodies is present. [ABSTRACT FROM AUTHOR]

Subsurface pressures strongly influence the migration and trapping of hydrocarbons and impact the safety and efficiency of drilling operations. The pore pressure field of the northern Gulf of Mexico (GOM) was analyzed at 1000-ft (305-m) depth intervals from 2500 to 17,500 ft (762 to 5334 m) below the sea floor. Two variables were mapped: 12,976 initial hydrocarbon reservoir pressure gradient values and 43,276 observations on drilling fluid (mud) weight. Because of the acute importance of assessing estimate uncertainty, ordinary kriging was employed, providing explicit evaluations of confidence surrounding mapped values. Expected values and confidence intervals for the distribution of both variables were estimated by 9 mi2 (23.3 km2) grid cells across the GOM for each of the 15 depth intervals. Estimation variances were also used to clip each map to specific extents, within which a uniform minimum threshold of certainty was exceeded. Characteristic of young basins with high sedimentation rates, mean pore pressure exceeded hydrostatic pressure throughout the GOM. Four provinces of internally consistent pressure regimes were defined: three south of Louisiana and one off the Texas coast. They reflect geologic controls on pressure arising from regional patterns of sedimentation and the resultant timing and geometry of salt tectonism. One GOM-wide (shallow) vertical transition in the pressure field was found in the mud weight data, and a second vertical transition (deep) occurred in both variables. Hot spot analysis was also applied to identify specific contiguous areas of abnormally high or low rates of change in pressure gradient and mud weight between depth-adjacent intervals. [ABSTRACT FROM AUTHOR]

In this study, mineralogical, geochemical, and isotopic data are presented for the Sylhet Trap at the southern flank of the eastern Shillong Plateau, northeastern India, to determine the magma genesis in relation to the Kerguelen plume mantle source. Sylhet Trap rocks are porphyritic tholeiite and have diverse chemical compositions from picro-basalt, basalt, andesite to dacite, but mostly are within the subalkaline field. Major and trace element data were used to identify two distinct magma fractionation trends, a low and medium K series, characterized by relatively flat MORB-like (analogous to Rajmahal Traps (II)) and enriched OIB chondrite-normalized Rare Earth Element (REE) patterns. Initial Sr/Sr, Nd/Nd, and Pb/Pb isotope compositions were widely varied, ranging from 0.70435-0.71357, 0.51196-0.51266, and 17.92-19.72, respectively, when compared with basalts from the West Bengal, the Rajmahal Traps and the Kerguelen plume. Correlations among isotopic and trace element ratios of the Sylhet Traps provide evidence for the involvement of (1) HIMU-like mantle component, (2) the Kerguelen plume-like component, and (3) EMII-like crustal component. Magma from the Sylhet Traps was originated from a melting that derived directly from the heterogeneous Kerguelen mantle plume (components 1 and 2), which strongly suggests the presence of the Kerguelen plume-head in the Bengal basin. [ABSTRACT FROM AUTHOR]

Assessment of the synchroneity between the Siberian Traps and the Permo-Triassic boundary (PTB) mass extinction has led to the proposition that the Siberian flood volcanism was responsible for the severest biotic crisis in the Phanerozoic. However, recent studies suggest that the Siberian Traps may have postdated the main extinction horizon. In this paper, we demonstrate, using stratigraphy, a time and intensity coincidence between PTB volcanic ash and the main extinction horizon. Geochemistry of the PTB volcanic ashes in five sections in South China indicates that they were derived from continental magmatic arc. Zircons extracted from the PTB volcanic ashes have negative εHf(t) (- 12.9 to - 2.0) and δ18O (6.8 to 10.9‰), consistent with an acidic volcanism and a crustal-derived origin, and therefore exclude a genetic link between the PTB mass extinction and the Siberian Traps. On the basis of spatial variation in the number of the PTB volcanic ash layers and the thickness of the ash layers in South China, we propose that the PTB volcanic ash may be related to Paleo-Tethys continental arc magmatism in the Kunlun area. Ignimbrite flare-up related to rapid plate subduction during the final assemblage of the Pangea super-continent may have generated a volcanic winter, which eventually triggered the collapse of ecosystem and ultimately mass extinction at the end of the Permian. The Siberian Traps may have been responsible for a greenhouse effect and so have been responsible for both a second pulse of the extinction event and Early Triassic ecological evolution. [ABSTRACT FROM AUTHOR]

The Early Permian Panjal Traps of northern India represent a significant eruption of volcanic rocks which occurred during the opening of the Neotethys Ocean. Basaltic, basaltic-andesites, dacitic and rhyolitic rocks collected from Guryal Ravine and Pahalgam show evidence for subaerial and subaqueous eruptions indicating that they are contemporaneous with the formation of a shallow marine basin. The major and trace element geochemistry of the basalts is consistent with a within-plate setting and there are basalts which have high-Ti (TiO2 > 2.0 wt.%) and low-Ti (TiO2 < 1.8 wt.%) compositions. The 'high-Ti' basalts are similar to OIB whereas the 'low-Ti' basalts are similar to continental tholeiites. The identification of 'high- and low-Ti' basalts within the Panjal Traps is analogous to other large igneous provinces (e.g. Karoo, Deccan, Parana, Emeishan). The Sr-Nd isotopic values (εNd(T) = - 5.3 to + 1.3; ISr = 0.70432 to 0.71168) of both types of basalts overlap indicating that the rocks may have originated from the same ancient subcontinental lithospheric (i.e. EMII-like) mantle source (TDM = ~ 2000 Ma). The two groups of basalts can be modeled by using a primitive mantle source and different degrees of partial melting where the high-Ti rocks are produced by ~ 1% partial melting of a spinel peridotite source whereas the low-Ti rocks are produced by ~ 8% partial melting. Trace elemental and isotope modeling indicates that some of the basalts assimilated ≤ 10% crustal material. In contrast, the basaltic-andesites are likely formed by mixing between basaltic magmas and crustal melts which produced rocks with higher SiO2 (~ 55 wt.%) content and enriched isotopic signatures (εNd(T) = - 6.1; ISr = 0.70992). The Panjal Trap volcanism was likely due to partial melting of the SCLM within a passive extensional setting related to the rifting of Cimmeria from Gondwana. Contemporaneous volcanic and plutonic granitic rocks throughout the Himalaya are probably not petrogenetically related but are likely part of the same regional tectonic regime. [ABSTRACT FROM AUTHOR]

The middle Cenomanian - early Turonian Mishrif Formation, a major carbonate reservoir unit in southern Iraq, was studied using cuttings and core samples and wireline logs (gamma-ray, density and sonic) from 66 wells at 15 oilfields. Depositional facies ranging from deep marine to tidal flat were recorded. Microfacies interpretations together with wireline log interpretations show that the formation is composed of transgressive and regressive hemicycles. The regressive hemicycles are interpreted to indicate the progradation of rudist lithosomes (highstand systems tract deposits) towards distal basinal locations such as the Kumait, Luhais and Abu Amood oilfield areas. Transgressive hemicycles (transgressive systems tract deposits) represent flooding of the shallow carbonate platform and are recorded in oilfields such as Amara, Halfaya and Zubair. A sequence stratigraphic framework has been constructed for the Mishrif Formation based on correlation of the transgressive and regressive hemicycles which are separated by maximum flooding surfaces. Three third-order sequences are identified which show lateral and vertical facies variations depending on relative sea-level changes. Sequence boundaries are characterized by karstic, exposure and drowning features. Middle Cenomanian - Turonian eustatic sea-level changes together with regional-scale tectonic deformation of the Arabian Plate controlled the availability of accommodation space and therefore the depositional profile during development of each sequence. Both of these factors controlled the maximum flooding surfaces and sequence boundaries which have been identified. The sequence stratigraphic key surfaces presented in this study represent typical candidate horizons or datum surfaces for future seismic or resevoir modelling studies. Also, lateral facies variations in each transgressive-regressive sequence and associated carbonate bodies (i.e. prograding shelf margin, forced regressive wedge) may form important stratigraphic traps in the Mesopotamian Basin. [ABSTRACT FROM AUTHOR]

Abstract: Phase compositions and microtextures of ore minerals in intrusive traps of the western part of the Siberian Platform have been studied using scanning electron microscopy. Oxide and sulfide solid solutions crystallize at the magmatic stage; their grain and aggregate shapes are determined by the cooling rate of magmatic bodies. We have revealed a gradual transition of oxides from fine-grained texture in the quenching zone, through skeleton, case, and frame forms, to isometric aggregates of mixed crystals in the holocrystalline silicate matrix. Sulfide spheroids (either associated with oxides or separated from them) are changed by dissemination and nests. The chemical compositions of both oxides and sulfides are correlated with the petrochemical types of rocks. Chrome-spinels or chrome-enriched ulvospinels crystallize first in the most magnesian dolerites. Iron and titanium oxides with Mn, V, Mg, and Al impurities prevail in the rest rock varieties. As temperature decreases, ilmenite, ulvospinel, and titanomagnetite crystallize after chrome-spinels. Exsolution structures are very intricate for titanium and iron oxides and depend on the oxidation conditions and on the assemblage of impurities and their quantities. The first exsolution particles of ilmenite are more magnesian, while the following ones are more manganese. Subsolvus exsolution is accompanied by the release of impurities, grain stripping, and rearrangement and natural enrichment of ore material. Conjugate transformation of silicates and ore minerals results in aggregate pseudomorphs and minerals, such as titanite, zircon, and baddeleyite. Nickel-containing sulfides formed at the magmatic stage prevail in more magnesian rocks. Copper minerals are more diverse. These are polymorphic modifications of chalcopyrite and cubanite in ore solid solutions formed at the magmatic stage, chalcopyrite in paragenesis with monoclinic pyrrhotite in zones of hydrothermal metasomatites, and chalcopyrite in solid solutions with bornite and chalcosine and in assemblage with low-temperature sulfides. The obtained data on mineral structures and assemblages can be used as indicators to classify the genesis and formation types of ores. [Copyright &y& Elsevier]

A new method for the analysis of trace gases from fluid inclusions of minerals has been developed. The purge and trap GC–MS system is based on the system described by Nolting et al. (1988) and was optimized for the analyses of halogenated volatile organic compounds (VOCs) having boiling points as low as −128°C (carbon tetrafluoride). The sample preconcentration cold trap consists of a U-shaped glass lined steel tube (GLT™), that is immersed into a small liquid nitrogen Dewar vessel for cooling. A rapid desorption step heats up the preconcentration tube in <30s from −196°C to 200°C. The process is carried out by using a pressurized air stream to dissipate the liquid nitrogen followed by resistive heating of the trap. The design of the cold trap and the direct transfer of desorbed analytes onto the GC column via a deactivated capillary column retention gap made sample refocusing within the GC oven unnecessary. Furthermore, a special air-tight grinding device was developed in which samples ranging from soft halite (hardness 2, Mohs scale) to hard quartz (hardness 7) are effectively ground to average diameters of 1000nm or below, thereby releasing gases from fluid inclusions of minerals. The gases are then purged from the grinding chamber with a He carrier gas flow. The detection and quantitative determination of gases, such as SF6 and CF4 released from fluorites and CH3Cl from halite samples is demonstrated. [ABSTRACT FROM AUTHOR]

In hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay-volume estimations, fluid-types differentiation on the basis of conventional logs is not always conclusive. A case study is presented by use of advanced nuclear-magnetic-resonance (NMR) techniques in conjunction with advanced downhole-fluid-analysis (DFA) measurements and focused sampling from wireline formation testers (WFTs) to accurately assess the hydrocarbon-type variations. The saturation-profiling data from an NMR diffusion-based tool provides fluid-typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but at discrete depths only. Thus, the two measurements ideally complement each other. In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone to an oil zone, and then to a rich-gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas, is a dry-gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs. The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution. [ABSTRACT FROM AUTHOR]

In this paper, the effects of device self-heating on the extraction of traps activation energy are investigated through experimental measurements and numerical simulations. Neglecting the device temperature increase during the experimental measurements can lead to an underestimation of traps activation energies as well as nonoverlapping Arrhenius plots. It will be shown that said artifacts can be removed once device thermal resistance is known and used to correct the temperatures data points at which trap time constants are extracted. The correctness of the proposed method is also supported through numerical simulations carried out both by neglecting and considering thermal effects during the drain current transient measurements. Finally, the experimental results obtained are also suggesting a novel method for the extraction of device thermal resistance, which yielded comparable results with respect to those obtained with other experimental techniques. [ABSTRACT FROM AUTHOR]

Well logs, checkshot and 3-D seismic data have been evaluated to delineate oil bearing sand reservoirs, to determine the petrophysical parameters and to analyze the geologic structures within Maiti field. Three wells were evaluated and three hydrocarbon reservoirs were delineated. petrophysical parameters for the reservoir sands have porosity, φ range of 0.28 -0.35, permeability k(mD) range of 68-168, hydrocarbon saturation, Sh range of 0.65 to 0.68 and volume of shale Vsh range of 0.02 - 0.15. The average values of these petrophysical parameters were used to rank the three reservoirs R1, R2, R3. It was deduced that reservoir R1 is the most prolific reservoir while R2 is the least. The structural analysis shows a fault assisted anticlinal structure known as structural trap within Maiti field, Niger delta, Nigeria. [ABSTRACT FROM AUTHOR]

Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir. A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRTs) were identified on the basis of whole core and plug X-ray computed tomography (CT), nuclear magnetic resonance (NMR) T2, mercury injection capillary pressure (MICP), porosity, permeability, and thin-section analyses. Primary-drainage (PD) and imbibition water/oil relative permeability (bounding) curves were measured on all the five rock types by the steady-state (SS) technique by use of live fluids at full reservoir conditions with in-situ saturation monitoring (ISSM). Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone (TZ) by varying connate-water saturations. Hysteresis effects were observed between PD and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e., wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual-energy (DE) CT scanning and high-resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves that were explained by different pore-level fluid-flow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate-water saturation. Relative permeability to oil was explained on the basis of the occupancy of the oil phase at varying connate-water saturations. The change in the water relative permeability trend was addressed on the basis of the connectivity of water at the varying connate-water saturations. These results and interpretations introduced an improved understanding of the hysteresis phenomena and fluid-flow behavior in the TZ of a Cretaceous carbonate reservoir that can assist in the overall reservoir modeling and well planning. [ABSTRACT FROM AUTHOR]

Composition and physical properties vary within hydrocarbon reservoirs, even in well connected ones; it is of crucial interest to model this change in order to initialize the reservoir simulator. In this work, a non-isothermal model is used to depict changes in plus fraction molecular weight and it will be integrated into another non-isothermal model describing fluid compositional changes within a 3D reservoir. Previously, the model has been validated versus 1D real reservoir data. It will be used to model compositional change of real hydrocarbon in a synthetic 3D reservoir subjected to temperature gradient inx,y, andzdirections. [ABSTRACT FROM PUBLISHER]

Mesozoic sediments are source rocks for nearly half the world's hydrocarbon reserves. Hence, there is great interest in the oil industry to know the trap and sub-trappean sediment thickness and their extent in the trap covered regions of Jamnagar study area. The microbial prospecting method is applied in the Jamnagar sub-basin, Gujarat for evaluating the prospects for hydrocarbon exploration by investigating the anomalous abundance of n-pentane- and n-hexane-oxidizing bacteria of this area. A total of 150 near-surface soil samples were collected in Jamnagar sub-basin, Gujarat for the evaluation of hydrocarbon resource potential of the basin. In this study, bacterial counts for n-pentane-utilizing bacteria range between 1.09 × 10 and 9.89 × 10 cfu/g and n-hexane-utilizing bacteria range between 1.09 × 10 and 9.29 × 10 cfu/g. The adsorbed hydrocarbon gases consisting of ethane plus hydrocarbons (ΣC) of 1-977 ppb and n-pentane ( nC) of 1-23 ppb. The integrated geomicrobial and adsorbed soil gas studies showed the anomalous hydrocarbon zones nearby Khandera, Haripur, and Laloi areas which could probably aid to assess the true potential of the basin. Integrated geophysical studies have shown that Jamnagar sub-basin of Saurashtra has significant sediment thickness below the Deccan Traps and can be considered for future hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

Abstract: The superimposed basins in the Tarim Basin are characterized by multiple source-reservoir-caprock combinations, multiple stages of hydrocarbon generation and expulsion, and multi-cycle hydrocarbon accumulation. To develop and improve the reservoir forming theory of superimposed basins, this paper summarizes the progress in the study of superimposed basins and predicts its development direction. Four major progresses were made in the superimposed basin study: (1) widely-distributed of complex hydrocarbon reservoirs in superimposed basins were discovered; (2) the genesis models of complex hydrocarbon reservoirs were built; (3) the transformation mechanisms of complex hydrocarbon reservoirs were revealed; (4) the evaluation models for superimposed and transformed complex hydrocarbon reservoirs by tectonic events were proposed. Function elements jointly controlled the formation and distribution of hydrocarbon reservoirs, and the superimposition and overlapping of structures at later stage led to the adjustment, transformation and destruction of hydrocarbon reservoirs formed at early stage. The study direction of hydrocarbon accumulation in superimposed basins mainly includes three aspects: (1) the study on modes of controlling reservoir by multiple elements; (2) the study on composite hydrocarbon-accumulation mechanism; (3) the study on hydrocarbon reservoir adjustment and reconstruction mechanism and prediction models, which has more theoretical and practical significance for deep intervals in superimposed basins. [Copyright &y& Elsevier]

Permian Kaipaileicike (开派雷兹克) volcanic rocks approximately 0-200 m thick are drilled in the Tahe (塔河) field. The distribution of volcanic rocks and their potential to form hydrocarbon reservoirs are discussed based on the integrated interpretation of log and 3D seismic data. The volcanic rocks, mainly consisting of dacites and basalts, are sandwiched between the Lower Triassic and Lower Carboniferous and bounded by top and bottom unconformities. The dacites accumulated in a mound shape around volcanic craters, whereas the basalts are deposited in tabular or trough-fill geometries. Permian volcanic craters mainly located at the northwest corner of the Tahe field are identified from volcanic rock thickening, occurrence of volcanic breccias, structural arch of the top Permian, seismic attribute anomalies, and fault (piercing conduit) reflections. Along the northwest wing of a Carboniferous salt dome, a stratigraphic trap is formed by a northeast updip pinch-out of Permian volcanic rock. Oil indications within the trap are found in numerous wells. The reservoir volcanic rocks are mainly of the fracture-pore pattern and covered by the caprock of a Lower Triassic mudstone. The hydrocarbon reservoir, which can potentially be a medium-sized oil pool, is connected to Cambrian-Ordovician source rocks through normal faults along the salt dome boundary. [ABSTRACT FROM AUTHOR]

Abstract: The division and analysis of the genetic types of slope breaks will be helpful in studying the enrichment regularity of hydrocarbon reservoirs because the enrichment of hydrocarbon reservoirs is closely related to the shelf-slope break types in continental lake basins or sags in China. This paper analyses the types of basin margins in Qikou Sag by assessing the sag boundary fault characteristics and spatial combination patterns using high-resolution three-dimensional seismic data, well logs and other data. Basin margins were divided into four types: steep slope fault belts, multi-level step-fault belts, steep slope step-fault belts and slope break flexure belts. Different types of depositional systems developed near the different basin margins, and correspondingly, four types of sequence stratigraphic patterns were developed. According to the study of trap types that occur adjacent to the different slope-break zones, fault-controlled lithologic traps were the predominant trap type in fault-controlled slope break zones, and lithologic traps occurred in the sag centre distant from the boundary faults. Along the slope break flexure belt, different types of traps developed in different slope break levels; stratigraphic unconformity traps occurred within the first slope break level, and stratigraphic–lithologic traps and up-dip pinchout lithologic traps were found in the second slope break level. So the deployment of future exploration should be conducted at different levels in Qikou Sag. [Copyright &y& Elsevier]

Deformation of a hydrocarbon reservoir can ideally be used to estimate the effective stress acting on it. The effective stress in the subsurface is the difference between the stress due to the weight of the sediment and a fraction (effective stress coefficient) of the pore pressure. The effective stress coefficient is thus relevant for studying reservoir deformation and for evaluating 4D seismic for the correct pore pressure prediction. The static effective stress coefficient n is estimated from mechanical tests and is highly relevant for effective stress prediction because it is directly related to mechanical strain in the elastic stress regime. The corresponding dynamic effective stress coefficient a is easy to estimate from density and velocity of acoustic (elastic) waves. We studied n and a of chalk from the reservoir zone of the Valhall field, North Sea, and found that n and a vary with differential stress (over-burden stress-pore pressure). For Valhall reservoir chalk with 40% porosity, a ranges between 0.98 and 0.85 and decreases by 10% if the differential stress is increased by 25 MPa. In contrast, for chalk with 15% porosity from the same reservoir, a ranges between 0.85 and 0.70 and decreases by 5% due to a similar increase in differential stress. Our data indicate that a measured from sonic velocity data falls in the same range its for n, and that n is always below unity. Stress-dependent behavior of n is similar (decrease with increasing differential stress) to that of a during elastic deformation caused by pore pressure buildup, for example, during waterflooding. By contrast during the increase in differential stress, as in the case of pore pressure depletion due to production, n increases with stress while a decreases. [ABSTRACT FROM AUTHOR]

Rajahmundry Traps has been under geo-scientific investigations for over half a century; yet sketchy information is available on morphology and internal architecture of lavas. This study bridges this gap by describing the morphology of lava pile of Duddukuru area following Hawaiian scheme that relates a lava-type with a particular emplacement style. The lowest flow (Flow 1) at Duddukuru, overlying an infra-trappean bed is a thick pahoehoe sheet lobe with intermittent basal hummocky, P-type pahoehoe lobes representing slow, sub-aerial emplacement of lava parcels. Some of them also have cherty intercalations and morphology suggestive of possible interaction of lava with water or water-laden sediments. Hummocky lobes were over-ridden by subaerial emplacement of voluminous sheet lava, which developed multi-tier columnar joints probably due to inundation of lava-surface by water. Inter-trappean sediments were deposited above Flow 1 in the ensuing period of volcanic quiescence. The eruptive history of Duddukuru ended with sub-aerial outpouring of two consecutive a'a flows (Flows 2 and 3) separated by a thin red bole horizon. As pahoehoe lavas are known to travel long distances due to emplacement through thermally efficient mechanism of endogenous inflation and insulated melt transport whereas a'a lavas, in contrast, are cooling-limited flows which rarely attain lengths covered by pahoehoe lavas; it is probable that the pahoehoe and a'a flows of Duddukuru have not traveled comparable distances. A'a flows of Rajahmundry Traps traveling from far-off vents are, therefore, more unlikely despite temporal and chemical similarity of this lava-pile with upper parts of Western Deccan Basalt Group. [ABSTRACT FROM AUTHOR]

In the application of controlled source electromagnetics for reservoir monitoring on land, repeatability errors in the source will mask the time-lapse signal due to hydrocarbon production when recording surface data close to the source. We demonstrate that at larger distances, the airwave will still provide sufficient illumination of the target. The primary airwave diffuses downward into the earth and then is scattered back to the surface. The time-lapse difference of its recorded signal reveals the outline on the surface of the resistivity changes in a hydrocarbon reservoir under production. However, repeatability errors in the primary airwave can destroy the signal-to-noise ratio of the time-lapse data. We present a simple and effective method to remove the primary airwave from the data, which we call partial airwave removal. For a homogeneous half space and a delta-function type of source, the surface expression of the airwave does not depend on frequency. For this reason, the primary airwave can be subtracted from the data using recordings at two frequencies, one low enough with a skin depth of the order of the reservoir depth that is sensitive to the reservoir, the other high enough to only sense the near surface. The method does not affect secondary airwave components created by signals that have propagated through the earth and returned to the surface. We show that the method provides a direct indicator of production-related time-lapse changes in the reservoir. We illustrate this for several models, including a general 3D heterogeneous model and one with strong surface topography, for situations where survey repeatability errors are large. [ABSTRACT FROM AUTHOR]

Abstract: The Final-Phase Weyburn geochemical research program includes explicitly integrated yet conceptually distinct monitoring, modeling, and experimental components. The principal objectives are to monitor CO2-induced compositional evolution within the reservoir through time-lapse sampling and chemical analysis of produced fluids; to document the absence (or presence) of injected CO2 within reservoir overburden through analogous monitoring of shallow groundwater and soil gas; to predict intra-reservoir CO2 migration paths, dynamic CO2 mass partitioning among distinct trapping mechanisms, and reservoir/seal permeability evolution through reactive transport modeling; to assess the impact of CO2-brine-rock reactions on fracture flow and isolation performance through experimental studies that directly support the monitoring and modeling work; and to exploit a novel stochastic inversion technique that enables explicit integration of these diverse monitoring data and forward models to improve reservoir characterization and long-term forecasts of isolation performance. [Copyright &y& Elsevier]

Abstract: In April 2008 the first injection of supercritical CO2 started into the Tubåen Formation from the Snøhvit field, Barents Sea. At full capacity, the plan is to inject approximately 23 Mtons of CO2 via one well during a 30 year period. The aim of this study was to simulation the 30 years of injection of supercritical CO2 and the following long term (5000 years) storage of CO2 in the Tubåen formation. The formation is at approximately 2600 meters depth and is at 98 °C and 265 bars. The simulations suggested that, because of limited lateral permeability, the bottom hole pressure increases rapidly to more than 800 bars if an annual injection rate of 766000 tons is used. This is significantly higher than the fracture pressures for the formation, and it is therefore suggested that the aim to inject 23 Mtons over the planed 30 years may be unrealistic. To prevent fracturing due to increasing pressure, the bottom hole pressure constraint is applied that leads to significant decrease in the amount of CO2 injected. With the hysteresis property applied, reservoir pressure behavior is the same in the base case (no hysteresis); however, the CO2 plume is distributed over a smaller area than in the base case. Similar to the case of hysteresis, the diffusion flow case shows the CO2 plume to be distributed over a smaller area than in the base case, but reservoir pressure decreases more than in the other two cases. [Copyright &y& Elsevier]

Abstract: Evaluation of the Bass Basin’s suitability for CO2 storage has been undertaken by analysing several key basin analysis elements, including seal capacity and integrity, reservoir quality, petroleum systems modelling and CO2 migration and storage modelling. Seal geometry, capacity and integrity of the Demons Bluff Formation has been investigated to evaluate CO2 containment in the basin. The study revealed good to excellent sealing capacity for the Demons Bluff Formation and for the intraformational seals within the Eastern View Group (EVG). Faults traversing the reservoir/regional seal boundary, as well as faults intersecting the top of the regional seal were evaluated for future risk of reactivation. There is some risk of reactivation associated with N-E striking faults, fortunately these faults are mostly confined to the margins of the basin. Reservoirs of the Upper EVG generally have high porosity and permeability. Hydrocarbon migration and accumulation in the basin were simulated, to examine the petroleum potential of specific reservoirs within the basin. Migration models suggest most of the trapped hydrocarbons occur in the reservoir sands of the Middle EVG. Reservoirs of the Upper EVG were have received little hydrocarbon charge, except for the northeastern part of the basin. CO2 migration paths within reservoirs of the Upper EVG were simulated based on a buoyancy driven migration model. Migration pathways within the Upper EVG and CO2 accumulations under the regional seal were identified. In addition, total available pore volumes for CO2 storage associated with structural traps was calculated at >2 billionm3. [Copyright &y& Elsevier]

Neogene siliceous rocks are known to act as both reservoirs and seals. However, the role of diagenetic alteration in the development of hydrocarbon reservoirs, seals, and traps in such formations is poorly understood. This study proposes two new models for hydrocarbon traps involving siliceous rock reservoirs with well-developed matrix porosity. The models are based on observations from the Yurihara and Toyotomi fields in Japan to evaluate changes in petrophysical properties associated with confining pressure and diagenetic transformations from opal-CT to quartz. When this diagenetic transformation boundary is located at depths greater than approximately 1000 m (~3300 ft), the overlying opal-CT porcelanite layer forms a seal and the underlying clay-poor quartzose porcelanite forms a reservoir, facilitating the development of a hydrocarbon trap. The quartzose porcelanite containing less than 6% Al2O3 (an indication of clay content) can act as a reservoir even 1000 m (3300 ft) below the boundary. When the boundary is located at depths shallower than approximately 500 m (~1650 ft), the overlying opal-CT porcelanite is unable to form a seal because of lower confining pressures--although clay-poor quartzose porcelanite continues to be a good reservoir. However, clay-rich quartzose porcelanite intercalated with the reservoir can act as a seal. When the quartzose porcelanite contains greater than 15% Al2O3, it has the potential to seal at the depth of the boundary. The requirement for a seal drops to greater than 8% Al2O3 at 1000 m (3300 ft) below the boundary. [ABSTRACT FROM AUTHOR]

Primary basins form stratigraphically continuous successions on autochthonous salt and, therefore, in the northern Gulf of Mexico, contain all the components of a petroleum system (source, reservoir, trap, and seal). Most primary basins are encased entirely in salt or in some combination of salt and welds. Petroleum exploration in the deep-water Gulf of Mexico is currently focused on primary basin targets and increasingly those at their lateral boundaries. However, as these boundaries are commonly poorly imaged, robust structural models are critical to interpretation of their structural evolution and relative petroleum system risk. Using three-dimensional seismic data, we define three tectonostratigraphic provinces that characterize primary basin depocenters: (1) a disconnected salt-stock-canopy province in Mississippi Canyon; (2) an amalgamated salt-stock-canopy province in northern Atwater Valley, southeastern Green Canyon, Walker Ridge, and southern Keathley Canyon; and (3) a bucket-weld province in western Green Canyon, Garden Banks, and northern Keathley Canyon. We recognize six trap types in the primary basins: (1) autochthonous salt-cored folds, (2) turtle structures, (3) base-of-salt truncations, (4) salt feeders, (5) salt ridges, and (6) bucket welds. Most primary basin explorations to date have targeted traps in one of the first four styles. Future primary basin exploration will increasingly focus on the traps formed by bucket welds and salt-cored ridges. The contrasting evolution of these features has implications for reservoir continuity, charge access, and trap configuration. Of primary basin boundary trap types, salt feeders have the lowest petroleum system risk followed by bucket welds, with saltcored ridges having the highest risk. [ABSTRACT FROM AUTHOR]

Abstract: Rhodococcus erythropolis strain NTU-1 degraded C10–C32 n-alkanes in diesel oil or crude oil. While degrading these n-alkanes, NTU-1 also trapped most other oil constitutes that were not degraded in biofloccules. In batch cultures with 10,000ppmv diesel or crude oil, approximately 90% oil removal was achieved within 4 days (about 30% of biodegradation and 60% of biosorption). In bioreactors with aeration and pH adjustment, an intermittent feed of 42,000ppmv n-hexadecane resulted in approximately 87% removal within 4 weeks (24% of biodegradation and 63% of biosorption), and an intermittent feed of 35,000ppmv diesel or crude oil resulted in more than 90% removal within 2 weeks (about 20% of biodegradation and 74% of biosorption). The results demonstrate the feasibility for the application of R. erythropolis strain NTU-1 to the bioremediation of sites polluted with petroleum spills. [ABSTRACT FROM AUTHOR]

Abstract: Subtle traps have become an important petroleum play type for exploration in the Dongying Depression, Bohai Bay Basin, eastern China. The majority of the oil pools are in the middle interval of the Es 3 member of the Eocene–Oligocene Shahejie Formation, with the subtle traps being primarily in the lenticular, basin floor turbidite sands enclosed within basin floor mudstones. Detailed geochemical investigation of 68 oil and rock samples from the depression reveals that in contrast to previous models, the oils from the subtle traps correlate poorly with the surrounding source rocks. While the high pristane/phytane (Pr/Ph > 1) and low gammacerane/C30-hopane ratios in these source rocks represent a freshwater lacustrine setting, the oils feature low Pr/Ph ratios (<1) and relatively high gammacerane contents similar to the upper source rocks deposited in a brackish lacustrine setting. The compound-specific isotope ratios of n-alkanes in the oils have intermediate values between those observed in extracts from the lower Es 3 and upper Es 4 source rocks. Consequently, the oils in the subtle traps were most likely derived from mixed and sources, with the contribution from the source rocks being predominant. The oils generated from the source rocks must have migrated through a thick interval of the source rocks to reach the subtle traps in the , through which there are no apparent structural nor stratigraphic pathways. The traditional migration and accumulation model, i.e. indigenous crude oil with short migration distance to lenticular oil pools, should be revised to account for the charging of oils from source rocks. [ABSTRACT FROM AUTHOR]

The article focuses on the development of trap intrusions in the sedimentary cover of the Siberian Platform. It states that the most complete data for the wide development of trap intrusions was obtained as a result of oil and gas prospecting in the Siberian Platform. It says that three samples were collected from the holes of Kt-1, Gf-4 and SV-1 and the data were obtained using the 40Ar/39Ar method. It reveals that new data for the intrusive traps of the Siberian Platform shows evidence of the occurrence of trap magmatism in the different blocks of the sedimentary cover.

Primary and secondary migrations are well defined terms in hydrocarbon reservoir genesis, as spontaneous hydrocarbon displacement from the source rock to the final trap. The fluid movement that occurs after reservoir abandonment defines the tertiary migration process. The result of the tertiary migration is a new saturation distribution within the reservoir and it is expected that in the most favorable cases, the production potential of some parts of the reservoir might be restored. The principles and factors involved in the tertiary migration process are examined and two successful production restarting projects in Romania are presented, as proof of the new concept effectiveness. [ABSTRACT FROM AUTHOR]

Three-dimensional (3-D) coupled deformation and fluid-flow numerical modeling are used to simulate the response of a relatively complex set of trap-bounding faults to extensional reactivation and to investigate hydrocarbon preservation risk for structural traps in the offshore Bonaparte Basin (Laminaria High, the Timor Sea, Australian North West Shelf). The model results show that the distributions of shear strain and dilation as well as fluid flux are heterogeneous along fault planes inferring lateral variability of fault seal effectiveness. The distribution of high shear strain is seen as the main control on structural permeability and is primarily influenced by the structural architecture. Prereactivation fault size and distribution within the modeled fault population as well as fault corrugations driven by growth processes represent key elements driving the partitioning of strain and up-fault fluid flow. These factors are critical in determining oil preservation during the late reactivation phase on the Laminaria High. Testing of the model against leakage indicators defined on 3-D seismic data correlates with the numerical prediction of fault seal effectiveness and explains the complex distribution of paleo- and preserved oil columns in the study area. [ABSTRACT FROM AUTHOR]