Fluid mapping in deeply buried Ordovician paleokarst reservoirs in the Tarim Basin,western China

The storage spaces within deeply buried Ordovician paleokarst reservoirs in the Tarim Basin are mostly secondary and characterized by strong heterogeneity and some degree of anisotropy. The types of fluids that fill the spaces within these reservoirs are of great importance for hydrocarbon exploration and exploitation. However, fluid identification from seismic data is often controversial in this area because the seismic velocity for this particular reservoir could be significantly influenced by many factors, including pore shapes, porosity, fluid types, and mineral contents. In this study, we employ the differential effective medium‐Gassmann rock physics model to interpret and discuss the characteristics of conventional karstic carbonate reservoirs in the Tarim Basin that are filled with different fluids (oil, gas, and water) using logging data and thus objectively build corresponding fluid identification criteria. These criteria are subsequently evaluated by amplitude versus offset (AVO) forward analysis based on typical logging data and further applied to ascertain the reservoir fluid types in two different areas in the Tarim Basin based on prestack inversion results. For conventional carbonate reservoirs, gas can be distinguished from heavy oil and water, but heavy oil and water are broadly similar on seismic data. For condensate carbonate reservoirs, water can be differentiated from light oil (i.e., condensates) and gas, but light oil and gas demonstrate substantial similarities in terms of their seismic responses. The predicted fluid results are in good agreement with the results of drilling and oil testing. In particular, modeling the seismically resolvable reservoirs in the carbonate strata in the Tarim Basin, which have needle‐ and sphere‐shaped storage spaces (pore aspect ratio > 0.3) and clay content that is lower than 5%, indicates that fluid properties could be properly evaluated if the porosity is larger than 5% for conventional carbonate reservoirs and >7% for condensate carbonate reservoirs.     

High‐Resolution 3D Marine Seismic Investigation of Hedeby Harbour,Germany

Offshore 3D‐seismic acquisition has been a standard for high‐precision structural imaging in the oil and gas industry for many years. Recently this technique has been adapted by only a few teams to the resolution required for archaeological marine investigation. In contrast to sonar techniques, the 3D‐seismic method produces images below the sea‐floor. We investigate the harbour of the Viking age proto‐town of Hedeby in Northern Germany with the SEAMAP‐3D system. SEAMAP‐3D allows for rapid acquisition and employs an automated data processing sequence. We observe a wealth of archaeologically relevant detail and compare our results with previous work.     

Unravelling the petroleum system by enhancing fluid migration paths in seismic data using a neural network based pattern recognition technique

Understanding the hydrocarbon migration system in the sub‐surface is a key aspect of oil and gas exploration. It is well known that conventional 3D seismic data contains information about hydrocarbon accumulations. Less known is the fact that 3D seismic data also contains information about hydrocarbon migration paths in the form of vertical noise trails. A method has been developed to highlight vertical noise trails in seismic data semi‐automatically, using assemblies of directive multi‐trace seismic attributes and neural network technology. The results of this detection method yield valuable information about the origin of hydrocarbons, about migration paths from source to prospect and about leakage or spillage from these prospects to shallow gas pockets or to the sea bed. Besides, the results reveal the sealing quality of faults, provide information on overpressure and whether prospects are charged or not. All these aspects are useful information for basin modelling studies and for an increased understanding of the petroleum system.     

Knee Ankyloses Associated with Tuberculosis from the Medieval Hungary – Differential Diagnosis Based on Medical Imaging Techniques

Osseous ankylosis of large joints that occurs secondary to infection is rarely described in developed countries, thanks to diagnostic techniques that allow early detection and treatment of the underlying infection. Evidence of the natural history and progression of the disease is now primarily studied through the observation and analysis of osteoarcheological specimens, and medical reports or books dating from the pre‐antibiotic era. This report illustrates several cases where modern medical imaging techniques and ancient medical literature were successfully interpreted to diagnose rare, advanced‐stage tuberculous alterations in osteoarcheological specimens. Two skeletons from the Bátmonostor cemetery (Hungary) demonstrate complete unilateral ankylosis of the knee. Macroscopic and radiographic examinations were undertaken to assess the extent of skeletal changes and determine their cause. Data obtained from computed tomography (CT) were constructed in 2D and 3D. The 2D CT images revealed cavities involving both the metaphyses and the epiphyses. The 3D reconstructions allowed us to reconstruct the more precise volumetric morphology of the circumscribed lytic lesions, as well as clear ‘image‐mirror’ lacunar volumes. On the basis of the macroscopic and radiological analyses, extra‐spinal tuberculous infection seems to have been the most probable etiology of these two cases. Copyright © 2012 John Wiley & Sons, Ltd.     

Quantitative basin modeling: present state and future developments towards predictability

A critique review of the state of quantitative basin modeling is presented. Over the last 15 years, a number of models are proposed to advance our understanding of basin evolution. However, as of present, most basin models are two dimensional (2‐D) and subject to significant simplifications such as depth‐ or effective stress‐dependent porosity, no stress calculations, isotropic fracture permeability, etc. In this paper, promising areas for future development are identified. The use of extensive data sets to calibrate basin models requires a comprehensive reaction, transport, mechanical (RTM) model in order to generate the synthetic response. An automated approach to integrate comprehensive basin modeling and seismic, well‐log and other type of data is suggested. The approach takes advantage of comprehensive RTM basin modeling to complete an algorithm based on information theory that places basin modeling on a rigorous foundation. Incompleteness in a model can self‐consistently be compensated for by an increase in the amount of observed data used. The method can be used to calibrate the transport, mechanical, or other laws underlying the model. As the procedure is fully automated, the predictions can be continuously updated as new observed data become available. Finally, the procedure makes it possible to augment the model itself as new processes are added in a way that is dictated by the available data. In summary, the automated data/model integration places basin simulation in a novel context of informatics that allows for data to be used to minimize and assess risk in the prediction of reservoir location and characteristics.     

Pressure distribution in a reservoir affected by capillarity and hydrodynamic drive: Griffin Field, North West Shelf, Australia

The effects of capillarity in a multilayered reservoir with flow in the aquifer beneath have characteristic signatures on pressure–elevation plots. Such signatures are observed for the Griffin and Scindian/Chinook fields of the Carnarvon Basin North West Shelf of Australia. The Griffin and Scindian/Chinook fields have a highly permeable lower part to the reservoir, a less permeable upper part, and a low permeability top seal. In the Griffin Field there is a systematic tilt of the free‐water level in the direction of groundwater flow. Where the oil–water contact occurs in the less permeable part of the reservoir, it lies above the free‐water level due to capillarity. In addition to these observable hydrodynamic and capillary effects on hydrocarbon distribution, the multi‐well pressure analysis shows that the gas–oil contacts in the Scindian/Chinook fields occur at different elevations. For both the Griffin and Scindian/Chinook fields the oil pressure gradients from each well are non‐coincident despite continuous oil saturation, and the difference is not attributable to data error. Furthermore, the shift in oil pressure gradient has a geographical pattern seemingly linked to the hydrodynamics of the aquifer. The simplest explanation for all the observed pressure trends is an oil leg that is still in the process of equilibrating with the prevailing hydrodynamic regime.     

Experimental study of the effect of variation in in‐situ stress on capillary residual trapping during CO2 geo‐sequestration in sandstone reservoirs

During a geo‐sequestration process, CO₂ injection causes an increase in reservoir pore pressure, which in turn decreases the reservoir net effective stress. Changes in effective stress can change all the reservoir and cap‐rock properties including residual saturations. This article presents the results of an experimental work carried out to understand the potential change in the volumes of residually trapped CO₂, while the porous medium tested underwent change in the net effective stress under in‐situ reservoir conditions of pore pressure and temperature. The experimental results obtained show that an initial 1725 psi (11.9 MPa) decrease in the net effective pressure caused 1.4% reduction in the volumes of residually trapped CO₂, while another 1500 psi (10.3 MPa) reduction caused a further 3.2% drop in the residual saturation of CO₂.     

Improving the interpretability of 3D GPR data using target–specific attributes: application to tomb detection

Three–dimensional (3D) ground–penetrating radar (GPR) represents an efficient high–resolution geophysical surveying method allowing to explore archaeological sites in a non–destructive manner. To effectively analyze large 3D GPR data sets, their combination with modern visualization techniques (e.g., 3D isoamplitude displays) has been acknowledged to facilitate interpretation beyond classical time–slice analysis. In this study, we focus on the application of data attributes (namely energy, coherency, and similarity), originally developed for petroleum reservoir related problems addressed by reflection seismology, to emphasize temporal and spatial variations within GPR data cubes. Based on two case studies, we illustrate the potential of such attribute based analyses towards a more comprehensive 3D GPR data interpretation.     

Hydrologic and geochemical controls on soluble benzene migration in sedimentary basins

The effects of groundwater flow and biodegradation on the long‐distance migration of petroleum‐derived benzene in oil‐bearing sedimentary basins are evaluated. Using an idealized basin representation, a coupled groundwater flow and heat transfer model computes the hydraulic head, stream function, and temperature in the basin. A coupled mass transport model simulates water washing of benzene from an oil reservoir and its miscible, advective/dispersive transport by groundwater. Benzene mass transfer at the oil–water contact is computed assuming equilibrium partitioning. A first‐order rate constant is used to represent aqueous benzene biodegradation. A sensitivity study is used to evaluate the effect of the variation in aquifer/geochemical parameters and oil reservoir location on benzene transport. Our results indicate that in a basin with active hydrodynamics, miscible benzene transport is dominated by advection. Diffusion may dominate within the cap rock when its permeability is less than 10^?19 m². Miscible benzene transport can form surface anomalies, sometimes adjacent to oil fields. Biodegradation controls the distance of transport down‐gradient from a reservoir. We conclude that benzene detected in exploration wells may indicate an oil reservoir that lies hydraulically up‐gradient. Geochemical sampling of hydrocarbons from springs and exploration wells can be useful only when the oil reservoir is located within about 20 km. Benzene soil gas anomalies may form due to regional hydrodynamics rather than separate phase migration. Diffusion alone cannot explain the elevated benzene concentration observed in carrier beds several km away from oil fields.     

Real‐time mud gas logging and sampling during drilling

Continuous mud gas loggings during drilling as well as offline mud gas sampling are standard procedures in oil and gas operations, where they are used to test reservoir rocks for hydrocarbons while drilling. Our research group has developed real‐time mud gas monitoring techniques for scientific drilling in non‐hydrocarbon formations mainly to sample and study the composition of crustal gases. We describe in detail this technique and provide examples for the evaluation of the continuous gas logs, which are not always easy to interpret. Hydrocarbons, helium, radon and with limitations carbon dioxide and hydrogen are the most suitable gases for the detection of fluid‐bearing horizons, shear zones, open fractures, sections of enhanced permeability and permafrost methane hydrate occurrences. Off‐site isotope studies on mud gas samples helped reveal the origin and evolution of deep‐seated crustal fluids.     

Geophysical signatures associated with fluid flow and gas hydrate occurrence in a tectonically quiescent sequence,Qiongdongnan Basin,South China Sea

Interpretation of high‐resolution two‐dimensional (2D) and three‐dimensional (3D) seismic data collected in the Qiongdongnan Basin, South China Sea reveals the presence of polygonal faults, pockmarks, gas chimneys and slope failure in strata of Pliocene and younger age. The gas chimneys are characterized by low‐amplitude reflections, acoustic turbidity and low P‐wave velocity indicating fluid expulsion pathways. Coherence time slices show that the polygonal faults are restricted to sediments with moderate‐amplitude, continuous reflections. Gas hydrates are identified in seismic data by the presence of bottom simulating reflectors (BSRs), which have high amplitude, reverse polarity and are subparallel to seafloor. Mud diapirism and mounded structures have variable geometry and a great diversity regarding the origin of the fluid and the parent beds. The gas chimneys, mud diapirism, polygonal faults and a seismic facies‐change facilitate the upward migration of thermogenic fluids from underlying sediments. Fluids can be temporarily trapped below the gas hydrate stability zone, but fluid advection may cause gas hydrate dissociation and affect the thickness of gas hydrate zone. The fluid accumulation leads to the generation of excess pore fluids that release along faults, forming pockmarks and mud volcanoes on the seafloor. These features are indicators of fluid flow in a tectonically‐quiescent sequence, Qiongdongnan Basin. Geofluids (2010) 10 , 351–368     

Direct inversion of Young's and Poisson impedances for fluid discrimination

Seismic inversion with prestack seismic data such as amplitude variation with offsets (AVO) inversion is an important tool in the estimation of elastic parameters for predicting lithology and discriminating fluid in conventional or unconventional hydrocarbon reservoirs. The product of Young's modulus and density (Young's impedance, YI) and the product of Poisson ratio and density (Poisson ratio impedance, PI) show great potential in lithology prediction and fluid discrimination of unconventional resources such as shale gas or oil. The high quality requirements for prestack data in density inversion render the estimation of YI and PI arduous and inaccurate with a conventional prestack inversion approach. In this study, a direct AVO inversion approach is proposed to estimate YI, PI, and density directly from P‐wave seismic data. The linearized P‐wave reflectivity approximate equation in terms of YI, PI, and density is initially derived. Five models, including four typical AVO classes, are utilized to verify the accuracy of the derived linearized P‐wave reflectivity equation in comparison with the exact P‐wave reflectivity equation and the frequently used linearized reflectivity approximate equation involving P‐ and S‐wave velocities and density. Parameter sensitivity analysis illustrates that YI and PI can reasonably be estimated from P‐wave reflectivity if a decorrelation scheme is utilized in the inversion algorithm. In addition, a pragmatic AVO inversion using a Bayesian scheme is suggested for the direct inversion of YI and PI from prestack seismic data. Synthetic and field data examples demonstrate the feasibility of the proposed inversion approach in the estimation of YI and PI and show the potential of this approach in fluid discrimination.     

Diagenesis and elemental geochemistry under varying reservoir oil saturation in the Junggar Basin of NW China: implication for differentiating hydrocarbon‐bearing horizons

In this paper, we attempt to differentiate hydrocarbon‐bearing reservoir horizons of the Junggar Basin of NW China based on the characteristics of diagenesis and associated elemental geochemistry. Reservoirs at this site have varying levels of oil saturation that correlate with the degree of dissolution in minerals (e.g., calcite and feldspar). Four different horizons with varying diagenetic mineral assemblages were observed, including (i) kaolinite‐rich, oil‐dominated horizons, (ii) kaolinite–pyrite–hematite‐rich, oil–water‐dominated horizons, (iii) siderite–chlorite‐rich, water‐dominated horizons, and (iv) chlorite‐rich horizons with negligible hydrocarbon production. The mean MnO content of the representative diagenetic mineral (e.g., calcite) in each of the above horizons is >2.5, 2.0–2.5, 1.5–2.0, and <1.0 wt%, respectively. We propose that the above methodology can be used for the identification of reservoir hydrocarbon‐bearing horizons. We argue that the indicators presented here can be applied in oil exploration across the Junggar Basin.     

“Science can never demobilize”: the united states navy and petroleum geology, 1898–1924

This article traces how the US Navy crafted policy from the expert advice of American geologists. Between 1898 and 1924, the US Navy metamorphosed from a slow, coal‐burning fleet to a swift, oil‐burning one. The decision to convert naval vessels to oil consumed years of wrangling at the highest levels of the Department's bureaucracy. Central to this struggle was the guarantee of a secure petroleum supply in the face of perpetually bleak predictions by geologists suggesting that US oilfields might someday soon run dry. The Navy–geologist interaction influenced the Navy's decision to burn oil, as well as American land policy and tax law. The partnership led to increased government involvement in the oil industry and a prominent role for geologists in shaping federal oil policy.     

Relationship between deformation bands and petroleum migration in an exhumed reservoir rock,Los Angeles Basin,California, USA

An oil‐bearing sandstone unit within the Monterey Formation is exposed in the Los Angeles Basin along the Newport‐Inglewood fault zone in southern California. The unit preserves structures, some original fluids, and cements that record the local history of deformation, fluid flow, and cementation. The structures include two types of deformation bands, which are cut by later bitumen veins and sandstone dikes. The bands formed by dilation and by shear. Both types strike on average parallel to the Newport‐Inglewood fault zone (317°–332°) and show variable dip angles and directions. Generally the older deformation bands are shallow, and the younger bands are steep. The earlier set includes a type of deformation band not previously described in other field examples. These are thin, planar zones of oil 1–2 mm thick sandwiched between parallel, carbonate‐cemented, positively weathering ribs. All other deformation bands appear to be oil‐free. The undeformed sandstone matrix also contains some hydrocarbons. The oil‐cored bands formed largely in opening mode, similar to dilation bands. The oil‐cored bands differ from previously described dilation bands in the degree of carbonate cementation (up to 36% by volume) and in that some exhibit evidence for plane‐parallel shear during formation. Given the mostly oil‐free bands and oil‐rich matrix, deformation bands must have formed largely before the bulk of petroleum migration and acted as semi‐permeable baffles. Oil‐cored bands provide field evidence for early migration of oil into a potential reservoir rock. We infer a hydrofracture mechanism, probably from petroleum leaking out of a stratigraphically lower overpressured reservoir. The deformation bands described here provide a potential field example of a mechanism inferred for petroleum migration in modern systems such as in the Gulf of Mexico.     

Hydraulic and hydrochemical properties of deep sedimentary reservoirs of the Upper Rhine Graben,Europe

Hydraulic and hydrochemical data from several hundred wells mostly drilled by the oil and gas industry within the four deep carbonate and siliciclastic reservoirs of the Upper Rhine Graben area in France and Germany have been compiled, examined, validated and analysed with the aim to characterize fluids and reservoir properties. Due to enhanced temperatures in the subsurface of the Upper Rhine Graben, this study on hydraulic and hydrochemical properties has been motivated by an increasing interest in deep hydrogeothermal energy projects in the Rhine rift valley. The four examined geothermal reservoir formations are characterized by high hydraulic conductivity reflecting the active tectonic setting of the rift valley and its fractured and karstified reservoirs. The hydraulic conductivity decreases only marginally with depth in each of the reservoirs, because the Upper Rhine Graben is a young tectonically active structure. The generally high hydraulic conductivity of the reservoir rocks permits cross‐formation advective flow of thermal water. Water composition data reflect the origin and hydrochemical evolution of deep water. Shallow water to 500 m depth is, in general, weakly mineralized. The chemical signature of the water is controlled by fluid–rock geochemical interactions. With increasing depth, the total of dissolved solids (TDS) increases. In all reservoirs, the fluids evolve to a NaCl‐dominated brine. The high salinity of the reservoirs is partly derived from dissolution of halite in evaporitic Triassic and Cenozoic formations, and partly from the fluids residing in the crystalline basement. Water of all four reservoirs is saturated with respect to calcite and other minerals including quartz and barite.     

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO2 storage in the Weyburn field

This paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian‐age Midale Evaporite. This low‐permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO₂ is being injected into an oil reservoir for enhanced recovery and CO₂ storage. A technique for experimentally determining CO₂ breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N₂, CO₂ and CH₄ were measured with the selected seal‐rock samples. The maximum breakthrough pressure is over 30 MPa for N₂ and approximately 21 MPa for CO₂. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO₂ storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO₂/brine system is significantly reduced compared with that of a CH₄/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO₂ if the pressure during or after CO₂ injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO₂ storage site.     

Significance of large-scale sand injectites as long-term fluid conduits: evidence from seismic data

Sand injectites and related features that are interpreted to have formed by large‐scale, often sudden, fluid escape in the shallow (typically <500 m) crust are readily imaged on modern seismic data. Many of the features have geometrical similarity to igneous dykes and sills and cross‐cut the depositional stratigraphy. Sand injectites may be multiphase and form connected, high‐permeability networks that transect kilometre‐scale intervals of otherwise fine‐grained, low‐permeability strata. North Sea examples often form significant hydrocarbon reservoirs and typically contain degraded, low‐gravity crude oil. Fluid inclusion and stable isotope data from cements in sand injectites record a mixing of aqueous fluids of deep and shallow origin.     

Ground‐Penetrating Radar Velocity Determination and Precision Estimates Using Common‐Midpoint (CMP) Collection with Hand‐Picking,Semblance Analysis and Cross‐Correlation Analysis: A Case Study and Tutorial for Archaeologists

The most crucial parameter to be determined in an archaeological ground‐penetrating radar (GPR) survey is the velocity of the subsurface material. Precision velocity estimates comprise the basis for depth estimation, topographic correction and migration, and can therefore be the difference between spurious interpretations and/or efficient GPR‐guided excavation with sound archaeological interpretation of the GPR results. Here, we examine the options available for determining the GPR velocity and for assessing the precision of velocity estimates from GPR data, using data collected at a small‐scale iron‐working site in Rhode Island, United States. In the case study, the initial velocity analysis of common‐offset GPR profile data, using the popular method of hyperbola fitting, produced some unexpectedly high subsurface signal velocity estimates, while analysis of common midpoint (CMP) GPR data yielded a more reasonable subsurface signal velocity estimate. Several reflection analysis procedures for CMP data, including hand and automated signal picking using cross‐correlation and semblance analysis, are used and discussed here in terms of efficiency of processing and yielded results. The case study demonstrates that CMP data may offer more accurate and precise velocity estimates than hyperbola fitting under certain field conditions, and that semblance analysis, though faster than hand‐picking or cross‐correlation, offers less precision.