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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]

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]

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]

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]

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.

The ability to detect aligned fractures using seismic anisotropy provides a valuable tool for exploiting hydrocarbon reservoirs better. Perhaps the most direct way of identifying anisotropy is by observing shear wave splitting. However, the interaction of shear waves with subsurface structure is often complicated. Although fractures in hydrocarbon reservoirs are usually subvertical, shear waves recorded on downhole receivers from microseismic events in or near the reservoir are not likely to have travelled vertically. As such, interpreting splitting measurements made on such waves is a non-trivial problem. Here we develop an approach to model the effects of subsurface structure on non-vertically propagating shear waves. Rock physics theory is used to model the effects of sedimentary fabrics as well as fractures, allowing us to use shear wave splitting measurements to invert for aligned fractures. We use synthetic examples to demonstrate how it is possible to assess in advance how well splitting measurements will image structures, and how this is highly dependent on the available range of ray coverage. Finally, we demonstrate the inversion technique on a passive seismic data set collected during hydraulic fracture stimulation. Despite an unfavourable source–receiver geometry, the strike of an aligned fracture set is accurately identified. [ABSTRACT FROM AUTHOR]

Abstract: Based on petrophysical, magnetic, gravity, electric, seismic and drilling data, combined with geological regularities, this paper proposed an integrated approach for the distribution prediction and lithology recognition of volcanic rocks, as well as the exploration prospect and target optimization of hydrocarbon deposits. The exploration technology was improved in the application to exploration in the Ludong-Wucaiwan area in Junggar Basin. Some important viewpoints are concluded as follows: aeromagnetic anomaly gradient belts correspond to volcanic faults, faults control the distribution of volcanic rocks and accordingly their local structures, aeromagnetic anomaly gradient belts correspond to highly-developed fracture zones and are prospective areas for volcanic reservoirs. The proposed integrated approach is proven effective by the exploration drilling results with high-flow gas wells. [Copyright &y& Elsevier]

Methods for predicting the permeability and elastic properties of hydrocarbon reservoirs containing natural fractures are important for the production optimization and seismic characterization of fractured reservoirs. Effective medium theories may be used for this purpose but need to be validated using numerical calculations of the fluid flow and seismic properties for realistic fracture networks. The prediction of effective permeability and elastic properties using effective medium theories of fractured media are compared with numerical simulations using a discrete fracture network (DFN) containing two sets of non-orthogonal vertical fractures. Discrepancies between the permeability obtained from the simulations and using effective medium theory are attributed to an oversimplified treatment of fracture interconnectivity in the effective medium theory used. The simulations indicate that the effect of interconnectivity on fluid flow varies with stress and flow direction. By contrast, the effective elastic compliances obtained from numerical simulation and effective medium theory are in good agreement, even for relatively complicated fracture networks. Although permeability and seismic anisotropy both vary with stress, the relation between them is not simple. The variation in reflection amplitude with offset and azimuth is found to be sensitive to the ratio of the normal to shear compliance of the fractures, whereas permeability is less sensitive to this ratio. For the DFN studied, the permeability rapidly increases at high level of stress due to dilation of the fractures when the in situ stress field is strongly anisotropic. [ABSTRACT FROM AUTHOR]

Abstract: A simple experiment for capillary sealed trap shows that leakage would occur only from the weakest point in the trap. As an extens ion of this concept, the sequestrated and accumulated CO2 in the structural high may happen to leak from the unexpected weak point near the top of sealing layer. On the other hand, if CO2 were sequestrated into the flank of tilted aquifer, CO2 in separate phas e would migrate upward within aquifer with no CO2 leakage into the sealing layer above and leaving some residual amount behind. According to this concept, the best location for sequestration of CO2 could be the flank of the structure rather than the top. [Copyright &y& Elsevier]

Abstract: Deep-sea basalt aquifers have been identified for geological CO2 sequestration in worldwide locations and offer vast reservoir capacities, permanent geochemical trapping potential, and other deep-sea protections that significantly reduce the risk of post- injection leakage. Using site-specific criteria, we target basalt aquifers along seismic and aseismic oceanic ridges, and calculate the injection volume potential for each. Results indicate that these aquifers occur in many oceans and could sequester 2.3–11.5 Tt-C along seismic ridges and 5.9–29.6 Tt-C along aseismic ridges. The enormous size of these potential reservoirs warrants further research and pilot experiments in each geographic setting. [Copyright &y& Elsevier]

Abstract: Gravitational trapping of carbon dioxide in deep ocean sediments is attractive both for the long term stability provided by gravity as well as the large volume and hence storage capacity of deep ocean sediments at necessary depths. Unfortunately, most pelagic sediments suffer from extremely low permeability and are not expected to have an overlying mechanical seal, making emplacement of CO2 contingent upon large scale hydraulic fracturing and some mechanism of arresting fracture growth before reaching the seafloor. An experimental design is presented with the capability of testing a variety of proposed fracture arrest mechanisms. [Copyright &y& Elsevier]

Abstract: Previous research suggests that for many geological CO2 sequestration reservoirs, up to 60% of the injected CO2 will be trapped by capillary forces (irreducible saturation), a mechanism termed residual CO2 trapping. More specifically, our recent models of ongoing field tests of geological sequestration suggest that residual CO 2 trapping can be maximized if the CO2 plume rises a greater distance due to buoyancy (i.e., injection at the deepest part of a thick reservoir) and sweeps a larger area before coming in contact with low permeability caprock. Although this strategy maximizes the residual CO2 trapping in theory because CO2 plume contacts more pore spaces, it also increases the probability that upwelling- CO2 may come into contact with faults or other leakage pathways. Geological heterogeneity seems to play greater role with respect to residual CO2 trapping potential. To help clarify what processes and properties will maximize residual CO2 trapping and minimize CO2-buoyant flow, we conducted a systematic analysis of permeability () fields and its correlation structures. The fields served as primary parameterization of a numerical model describing CO2 migration during a 100-year simulation period. We compared various permutations of two-dimensional conceptual models, including homogeneous, random, homogenous with low- lens, and anisotropically-correlated fields. Using a Sequential Gaussian Simulation method, for most of models, we generated 10 realizations in each model permutation. In each simulation, the amount of mobile-, residual-, and aqueous-trapped CO2 was calculated and the spatial distribution of the CO2 plume was quantified using the first and second spatial moments. Both homogeneous and random simulation results suggest that the amount of residual trapped CO2 increases as the effective increases. These results imply that the overall velocity distribution, which governs the sweeping area of the CO2 plume, is a critical factor for residual CO2 trapping. However, as overall velocity (or field) increases, we observed that the CO2 plume reaches the caprock more quickly. In simulations of anisotropically correlated fields with specific correlation length ratios of 25 m×10 m,50 m×10 m, and 100 m×10 m in x (horizontal) and z (vertical) directions, respectively, the CO2 migration distance due to buoyancy force is shorter as the horizontal correlation length becomes greater. In addition, as the horizontal correlation length becomes greater, residual trapping increases because the CO2 plume spreads farther laterally, sweeping a larger area. In sum, results of this analysis suggest that heterogeneous fields with greater anisotropic correlation ratios tend to maximize residual trapping and minimize buoyancy-driven CO2 migration. Our findings also suggest that correlation structures, especially anisotropic media with specific ratios of correlation lengths, can strongly impact CO2 trapping mechanisms by controlling velocity and tortuosity, which in turn determines the sweeping area of CO2 plumes. [Copyright &y& Elsevier]

Abstract: The dynamic mass partitioning and spatial distribution of CO2 trapping mechanisms largely control the long-term isolation performance of geologic storage sites. Although the majority of these physical and chemical sinks have been well characterized individually, much less well defined is our understanding of their relative significance on a mass basis, how this mass partitioning varies as a function of key reservoir properties, and the manner in which partitioning dynamics correlate with isolation performance. In this paper, I first review the resume of trapping mechanisms, outline the fundamental boundary condition and process controls on their spatial distribution and mass partitioning, and describe the distinct distribution and partitioning characteristics of end-member structurally open and closed systems. I then discuss how mass partitioning varies with time, propose a new correlation between partitioning dynamics and isolation performance, and within this framework outline optimal reservoir settings for large-scale CO2 injection. [Copyright &y& Elsevier]

Abstract: We present a sharp-interface mathematical model of CO2 migration in saline aquifers, which accounts for gravity override, capillary trapping, natural groundwater flow, and the shape of the plume during the injection period. The model leads to a nonlinear advection–diffusion equation, where the diffusive term is due to buoyancy forces, not physical diffusion. For the case of interest in geological CO2 storage, in which the mobility ratio is very unfavorable, the mathematical model can be simplified to a hyperbolic equation. We present a complete analytical solution to the hyperbolic model. The main outcome is a closed-form expression that predicts the ultimate footprint on the CO2 plume, and the time scale required for complete trapping. The capillary trapping coefficient emerges as the key parameter in the assessment of CO2 storage in saline aquifers. The expressions derived here have immediate applicability to the risk assessment and capacity estimates of CO2 sequestration at the basin scale. In a companion paper [Szulczewski and Juanes, GHGT-9, Paper 463 (2008)] we apply the model to specific geologic basins. [Copyright &y& Elsevier]

Abstract: The effect of flow instabilities on capillary trapping mechanisms is a major source of uncertainty in CO2 sequestration in deep saline aquifers. Standard macroscopic models of multiphase flow in porous media are unable to explain and quantitatively predict the onset and structure of viscous-unstable flows, such as the displacement of brine by the injected CO2. We present the first step of a research effort aimed at the experimental characterization and mathematical (continuum) modeling of such flows. Existing continuum models of multiphase flow are unable to explain why preferential flow (fingering) occurs during infiltration into homogeneous, dry soil. We present a macroscopic model that reproduces the experimentally observed features of fingered flows. The proposed model is derived using a phase-field methodology and does not introduce new independent parameters. From a linear stability analysis, we predict that finger velocity and finger width both increase with infiltration rate, and the predictions are in quantitative agreement with experiments. [Copyright &y& Elsevier]

Abstract: The super-atomization of liquid CO2 aimed at stable geological storage has been performed. All of geological storage techniques are required to prevent rising up of injected CO2 due to buoyancy effect. As an example, caprock CO2 trapping prevents the CO2 rising up by impermeable layer, however this technique depends onto the geological structure and there are leakage risk. Therefore we proposed a new technique of trapping super-atomized liquid CO2 in the porous structure to realize stable geological storage and to boost the efficiency of storage. In this study, the super-atomization process and the emulsion stability have been observed. As the result, the liquid CO2 was able to be super-atomized the same scale as gap diameter of the sandstone aquifer. [Copyright &y& Elsevier]

Abstract: CO2 can be immobilized in an aquifer as a residual phase trapped by capillary forces. The “inject low and let rise” strategy of storing CO2 in d eep saline aquifers is one method to maximize residual trapping. The more uniform the saturation front during upward movement of CO2, the greater the amount of CO2 trapped in this form. Previous studies suggest that capillary pressure i s a secondary influence on the CO2 plume, and that the permeability field governs the major features of the rising plume. In this work we show that sp atially varying capillary entry pressure can cause qualitatively different plume behavior. To illustrate the behavior, we si mulate buoyancy-driven migration when supercritical CO2 is placed below brine in a heterogeneous domain. After generating geostatistical realizations of permeability, we apply the Leverett -function so that each grid block has a drainage curve ( vs ) physically consistent with its permeability. The behavior of the displacement front depends strongly on the correlation structure of the heterogeneity and upon the magnitude of entry pressure. In a relatively homogeneous domain, capillar ity is a second-order effect. It damps the tendency toward channeling of the rising CO2 front and increases the uniformity of the plume. As the heterogeneity of the aquifer increases, capillarity begins to dominate buoyancy. Regions with smaller permeability, through which single-phase flow would readily occur, can completely block rising CO2, simply because the capillary entry pressure in these regions is somewhat larger than in neighboring regions. These local capillary barriers prevent CO2 from rising and cause it to mov e laterally. The disruption can be so extreme that above-residual saturations of CO2 accumulate below these barriers. These local accumulations can remain undisturbed when the top seal of the aquifer is breached. Thus we distinguish them as a new mode of CO2 trapping, dubbed “local capillary trapping”. Overall, the displacement front is much less uniform in heterog eneous domains. Despite the nonuniformity, the extent of dissolution trapping remains significant, much more than would be expected considering the ramified structure of the displacement front. T he reduction in residual phase trapping is balanced by an increase in local capillary trapping. Thus the extent of immobilization is similar to that found in previous works. [Copyright &y& Elsevier]

Abstract: Safely sequestering CO2 in a deep saline aquifer requires calculating how much CO2 the aquifer can store. Since offsetting nationwide emissions requires sequestering large quantities of CO2, this calculation should apply at the large scale of geologic basins. The only method to calculate storage capacity at the basin scale, however, is not derived from multiphase flow dynamics, which play a critical role in CO2 storage. In this study, we explain a new model to calculate basin-scale storage capacity that is derived from flow dynamics and captures the dynamic phenomena of gravity override and capillary trapping. Despite the fact that the model is dynamic, it is simple since it is a closed form expression with few terms. We demonstrate how to apply it on the Fox Hills Sandstone in the Powder River Basin. [Copyright &y& Elsevier]

Abstract: Motivated by geological carbon dioxide (CO2) storage, we present a simple model for the migration of immiscible gravity currents with constant residual trapping in a two-dimensional confined and sloping aquifer. Residual trapping acts as a loss-term, it reduces the current volume as long as the CO2 plume continues to migrate. Comparison with numerical results shows that the hyperbolic limit of the governing equations is a good approximation for currents with large mobility. In gently sloping aquifers, the current evolution is divided into an initial stage, with power-law decrease of volume, and a later stage, characterized by a rapid decay of the plume volume. Our results suggest that the efficient residual trapping in dipping aquifers may allow CO2 storage in aquifers lacking structural closure, if CO2 is injected far enough from the outcrop of the aquifer. However, the poor vertical sweep may lead to very long migration distances that may limit the storage capacity of in such aquifers. All results presented here are based on [M.A. Hesse, F.M. Orr Jr, H.A. Tchelepi, Gravity currents with residual trapping, J. Fluid Mech. 611 (2008) 35–60.]. [Copyright &y& Elsevier]

Abstract: Numerical simulation using TOUGHREACT software has shown that more than 20Mt of CO2 can be stored for a period up to 10,000 years in a 2-D model system taking from the geology of the Tokyo Bay area. Carbonate precipitation occurs extensively in the front of enlarging plume, forming a shell enclosing CO2. The distribution of dawsonite is predicted to be dependent on the dissolution of plagioclase which presents abundantly in sandstones of the Tokyo Bay area as well as those in young sedimentary strata of Japanese Islands, suggesting its potential importance in the mineral trapping of CO2. [Copyright &y& Elsevier]

Abstract: Numerous research results have been published on the storage science and the technology of CO2 storage in saline aquifers to address the knowledge gaps identified by the IPCC Special Report on Carbon Capture and Storage in 2005. Significant progress has been made towards developing consistent methodologies for the classification and determination of CO2 storage capacity and towards comprehensive guidelines regarding site selection, site characterisation, risk assessment and monitoring and plans. Although advancements have been made with respect to geochemical processes and numerical simulations, a larger portfolio of CO2 storage operations is needed to provide realistic data for model calibration and substantiation of time frames for various trapping mechanisms. The experience from existing storage projects has shown that CO2 geological storage in saline aquifers is a technology that can be successfully and safely applied today. However, proper regulations for CO2 storage are needed to reduce the current uncertainty associated with the economics of CO2 storage and to accelerate the deployment of CCS technology. [Copyright &y& Elsevier]

Abstract: To utilize aquifers without proven seal structures as a CO2 storage reservoir, CO2 should be trapped by residual gas trapping and solubility trapping as well as physical trapping by cap-rock. We investigated the mechanism of the residual gas trapping from a microscopic point of view by means of micro-focused X-ray CT. First, we imaged trapped air bubbles in a Berea sandstone chip after spontaneous imbibition at atmospheric pressure. With the resolution of 6.52 m/pixel, 610 sheets of slice images of 608×608 pixels were reconstructed. Pore structure and trapped bubbles were clearly visualized. Next, distributions of trapped bubbles in Berea and Tako sandstone were imaged in core-flooding at the capillary number of 1.0×10−6. The trapped bubbles consist of two-type; one occupies the center of pore with a pore-scale size and the other has a pore-network scale size. In low porosity porous media such as sandstone, connected bubbles has high contribution to trapped gas saturation. The distributions of trapped bubbles were uniform throughout the core except for the heterogeneity due to sedimentary layers. With a packed bed of glass beads 600 μm in diameter, the effects of capillary number and the injected water volume were investigated. Even in the packed bed of glass beads, which has a high porosity of 38%, once the gas bubbles are trapped, they are stable against the water flow rate that corresponds to the capillary number of 1.0×10−4. Even at very high capillary number of 4.7×10−5, residual gas saturation is independent of volume of injected water up to 15 pore volumes. Third, distributions of the residual gas saturation in the core were measured at supercritical conditions on core scale. The effect of fracture on the residual gas saturation was also investigated. The fracture reduces the maximum CO2 saturation to about 20% at the end of CO2 injection. However, most of the CO2 were trapped after the water injection. The Land type relationship between trapped CO2 saturation and the maximum CO2 saturation was obtained for supercritical CO2. [Copyright &y& Elsevier]

Abstract: We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for carbon dioxide (CO2) storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO2 immobile. We used analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of 0.11 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation. [Copyright &y& Elsevier]

Abstract: Implementation of well completions enabling multiple hydrocarbon reservoirs to be produced by a single well can save production cost and enhance recovery. Aiming at the characteristics of the three types of oil and gas reservoirs in the Jabung block in Indonesia, namely, gas cap oil-rim reservoirs, multiple hydrocarbon reservoirs, and heterogeneous multiple-sand reservoirs, this article puts forward optimized completion methods by using conventional technology and down-hole equipment. The new methods are able to develop multireservoir sands at the same time or successively without additional completion jobs. In addition, the novel completion enables water injection wells to selectively control injection and improve the recovery of hydrocarbons. The above strategies have been applied to different types of reservoirs, providing an effective mean for maximizing hydrocarbon recovery, controlling operating expenditures, and improving the overall benefit of development wells. [Copyright &y& Elsevier]

Abstract: Affected by the South Tianshan orogenesis, the faulted structure patterns in the Wushi Sag are very complex. Aimed to find out the basic characteristics of the structures, this article studies many seismic profile sections, the regional geology, the structural patterns, and the formative stage of the structures. The Wushi Sag has three main fault patterns (face to face thrust, back to back thrust, sphenoid thrust), and many local fault structural patterns (fault-bend fold, fault-propagation fold, duplex structure, outburst structure, growth structure, etc.). There mainly develop four groups of reverse faults (NE, NEE, NW, EW) and one group of NNW trending strike-slip faults. According to the structural background, seismic profiles, and balanced cross sections, the main fault in the studied area experiences at least five evolving stages, which are, pre-Mesozoic, late Permian – early Tertiary, Jurassic, late Jurassic – early Cretaceous, and late Neogene. The structural styles have a close relationship with source rocks, hydrocarbon reservoirs, and the character and distribution of petroleum systems. [Copyright &y& Elsevier]

Abstract: The fold-and-thrust belt in the northwestern margin of the Junggar Basin is composed of the northern monocline belt, the middle syncline belt, the Ke-Wu thrust belt, and the frontal slope belt, and is divided into the upper and lower structural layers in vertical. The upper structural layer precedes the lower one in terms of thrust sequence. Inferred from the restoration of unconformities, the motion of thrust faults started in late Triassic, activated in succession in Jurassic, and stopped in Cretaceous. The footwall venture exploration should aim at “cap brim” traps, especially in the triangular region, where the Dazhuluogou tear fault and Ke-Wu thrust belt intersect and the exploration horizon imbeds moderately, and then aim at the deep anticline traps in duplex structures when obtaining the essential data of deep geology and the velocity data. [Copyright &y& Elsevier]

The Siberian traps rank among the largest flood basalt provinces in the world. Major magmatic activity is restricted to several short periods of less than 1 Myr around the Permo-Triassic boundary. We measured the anisotropy of magnetic susceptibility (AMS) of 183 basaltic samples from 28 individual lava flows belonging to the northwestern part of the flood basalt province, in order to test the reliability of such data in structural interpretation. These preliminary AMS data show a remarkably consistent pattern of magnetic lineations, that likely reflect the primary flow-related texture of the basalt. Our results also emphasize that AMS data are consistent with the well-documented petrological and geochronological data. The inferred flow directions are also consistent with flow directions expected from isopach maps. Our results suggest that the entire 2 km-thick lava pile was fed by fissure eruptions located in the rifted basin that bound the Siberian platform, and was controlled by topographical features, particularly major rift zones. [ABSTRACT FROM AUTHOR]

The possibility that substantial quantities of CO2 can be injected into subsurface porous rock formations has been investigated sufficiently to show that pore space available to contain the CO2 is abundant. Multiple rock types and physical mechanisms can be used to trap the CO2 indefinitely. With careful site selection and operations, leakage to the near-surface region can be avoided. The next step is to test these injection processes at the scale of a large power plant. [ABSTRACT FROM AUTHOR]

In this work, a nanoporous template with a controllable channel diameter was used to simulate the oil storage ability of shale pore throats. On the basis of the wetting behaviours at the nanoscale solid-liquid interfaces, the seepage of oil in nano-channels of different diameters was examined to accurately and systematically determine the effect of the pore diameter on the oil storage capacity. The results indicated that the lower threshold for oil storage was a pore throat of 20 nm, under certain conditions. This proposed pore size threshold provides novel, evidence-based criteria for estimating the geological reserves, recoverable reserves and economically recoverable reserves of shale oil. This new understanding of shale oil processes could revolutionize the related industries. [ABSTRACT FROM AUTHOR]