Search

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]

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]

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 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]

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]

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]

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]

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]

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]

This work deals with some aspects concerning the Hydrocarbon Reservoir Management and, particularly, the management of oil recovery by steam injection processes. The reservoir management purposes, the data required for a pertinent analysis, the steps in designing and implementing steamflood processes, the possibilities of estimating their performance by analytical and empirical methods, as well as the operational and performance parameters which must be evaluated for establishing the feasibility of the field application projects are presented. [ABSTRACT FROM AUTHOR]

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]

The founder of the Russian school of direct interpretation of potential fields (with minimal prior geological-geophysical information) was V.M. Berezkin, who introduced the operator of total normalized gradient for the 2D interpretation of profile gravity data sets. This operator was successfully applied in searches of hydrocarbon reservoirs. The further development of this approach (the so-called quasi-singular points method) has allowed solution also to various structural problems, using mathematical criteria for the transition from extremes of total normalized gradient fields to coordinates of anomalous sources. The main numerical evaluation strategy is based on stabilized downward continuation of field derivatives and specific use of the filtration properties of Fourier series approximation. The characteristic properties of the quasi-singular points method are: 1) presentation of a more general total normalized gradient function through additional parameters (derivative order m, form of smoothing function Q, number of Fourier coefficients N* with maximal N), optimum values being chosen during a peak-spectrum analysis of the interpreted function; 2) calculation of the set of total normalized gradient fields for various values of N*/ N, representing coordinate systems { x, N*/ N} as an ‘axes tree’ of extrema, where each 2D total normalized gradient field is representationally compressed in a 1D line, permitting a) immediate overview of the positions of the axes in all variants of the calculated fields and b) reduction of the retained information, as required in subsequent interpretation; 3) development of two criteria for transition from extrema of total normalized gradient fields to the coordinates of anomaly sources. The quasi-singular points method is intended for tracing limiting gently-sloping boundaries, if their micro-relief features are sources of the interpreted anomaly but sub-vertical contacts may also be traced. The method has been tested in delineating various geological structures. One of the most challenging, successfully achieved, was tracing of the Moho discontinuity and study of the upper mantle, using only Bouguer anomaly data along interpretation profiles. This is attested in an example of two regional profiles intersecting the European part of Russia. The central part of one of them coincides with the results from a deep seismic profile. [ABSTRACT FROM AUTHOR]

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]

The properties of hydrocarbon reservoirs are generally derived from core experiments and use theories of fluid flow that normally assume homogeneous core properties. Reservoirs, however, are generally heterogeneous, and interpretations of the results of these experiments are likely to be unreliable if the core from which the data are derived is heterogeneous. This article examines experimentally immiscible displacement through well-defined permeability heterogeneities, modeled using 2-D visual models packed with clear beads of different permeabilities. The results indicated that the displacement patterns were dominated by capillary pressure effects and that they were different from those found in miscible systems. This understanding is needed, since in reservoir simulators, the simulator codes must contain the correct physics, and in core analysis, the effluent profiles must be correctly interpreted for sensible predictions. [ABSTRACT FROM AUTHOR]

The history matching (HM) hydrocarbon reservoir inverse problem is ill-posed because its solution may be non-unique or unstable. Variability of acceptable solutions around local minima may be very large. Nonetheless, it is a common practice in HM to find a unique reservoir model, although there is no guarantee that this model represents the geology. Qualitative geological information is generally not considered because of difficulties to express them mathematically. Here, we incorporate 'smoothness' in the spatial variation of physical properties as an example of a geological qualitative constraint that can be mathematically incorporated in an objective function also honouring the data. The constraint is valid if lateral continuity exists (e.g. fluvial-deltaic siliciclastic reservoirs). We mean smoothness by conditioning the permeability and/or porosity difference between adjacent grid blocks to be small. We use a synthetic 2D water-oil model and a solution search technique allowing characterising both the optimum solution and its variability. The smoothness constraint reduces the variance of the estimates by introducing bias in the solutions still preserving good match. The key point to achieve an optimum trade-off between stability and data match is the tuning of the parameter, controlling the relative importance of the constraint in the objective function. The smoothness constraint cannot be applied to all reservoirs. However, we corroborate the idea that a 'tool box' of HM can be designed; each 'tool' can incorporate a different constraint. Therefore, the interpreter can judiciously choose a specific tool from this tool box according to the adherence of its constraint to the particular reservoir being studied. [ABSTRACT FROM AUTHOR]

The article analyzes the results of the exploratory effort in the South-Caspian Basin and the causes of failures to discover substantial hydrocarbon reserves in 1995 through 2005. A geologic concept is proposed that may help improve exploratory drilling efficiency. The region's reserves and resources are evaluated. [ABSTRACT FROM AUTHOR]

The change in reservoir pore pressure due to the production of hydrocarbons leads to anisotropic changes in the stress field acting on the reservoir. Reservoir stress path is defined as the ratio of the change in effective horizontal stress to the change in effective vertical stress from the initial reservoir conditions, and strongly influences the depletion-induced compaction behaviour of the reservoir. Seismic velocities in sandstones vary with stress due to the presence of stress-sensitive regions within the rock, such as grain boundaries, microcracks, fractures, etc. Since the response of any microcracks and grain boundaries to a change in stress depends on their orientation relative to the principal stress axes, elastic-wave velocities are sensitive to reservoir stress path. The vertical P- and S-wave velocities, the small-offset P- and SV-wave normal-moveout (NMO) velocities, and the P-wave amplitude-versus-offset (AVO) are sensitive to different combinations of vertical and horizontal stress. The relationships between these quantities and the change in stress can be calibrated using a repeat seismic, sonic log, checkshot or vertical seismic profile (VSP) at the location of a well at which the change in reservoir pressure has been measured. Alternatively, the variation of velocity with azimuth and distance from the borehole, obtained by dipole radial profiling, can be used. Having calibrated these relationships, the theory allows the reservoir stress path to be monitored using time-lapse seismic by combining changes in the vertical P-wave impedance, changes in the P-wave NMO and AVO behaviour, and changes in the S-wave impedance. [ABSTRACT FROM AUTHOR]

The area comprising the NE Nile Delta and adjacent northern Sinai is an important hydrocarbon province in Egypt, but the origin of the hydrocarbons and their migration is not fully understood. In this paper, we evaluate organic source facies and assess the results of basin modelling in order to improve our understanding of the regional petroleum system. Organic-geochemical and petrographic analyses of 800 rock samples ranging in age from Early Jurassic to Pleistocene were used in this study. Most of the samples studied had moderate to high TOC contents, and kerogen was a mixture of Types II and III with a wide range of petroleum generation potentials from very poor to very good. Thermal and burial history models indicate that the source rocks entered the early-mature/mature stage in very recent times (Pleistocene to Recent). The top of the oil window ranges in depth from 1,800 m to 4,500 m, whereas the bottom of the oil window was not reached by most of the studied wells. In combination with numerical modelling results, structure contour maps for key horizons reveal possible migration trends and prospective areas. We tentatively identify prospective targets for hydrocarbon exploration, both in the Tertiary sequence and in the Cretaceous succession, especially where carbonate build-ups are present. [ABSTRACT FROM AUTHOR]

The thermal diusion phenomena, also known as the Soret eect, is important for the study of compositional variation in hydrocarbon reservoirs. Several theoretical models have been developed over the years to predict the thermodiusion coefficient of an organic mixture. Firoozabadi et al. [1] developed an analytical relationship between the thermal, molecular, and pressure diusion coefficients based on the approach of Dougherty and Drickamer [2]. The distinctive feature of Firoozabadi's model is its ability to be used not only for binary mixtures but also for multicomponent mixtures. The verification of Firoozabadi's model by numerical simulations was limited to binary mixtures only because of a lack of experimental data on thermodiusion coefficients in multicomponent hydrocarbon mixtures. However, Platten et al. [3] were able to measure the thermodiusion coefficients of a ternary hydrocarbon mixture experimentally by utilizing the thermogravitational column technique, hence making it possible to verify the theoretical model. This paper will compare the density, thermodiusion, and molecular diusion coefficients obtained with the Fontainebleau benchmark values for binary mixtures of n-dodecane, isobutylbenzene, and tetrahydronaphtalene. The accuracy of the numerical results from the Firoozabadi's model for ternary hydrocarbon mixtures is investigated. Results reveal a positive agreement between experimental and numerical data. [ABSTRACT FROM AUTHOR]

Abstract: This article introduces a methodology for integrating geochemical data in reservoir simulations to improve hydrocarbon reservoir models. The method exploits routine measurements of naturally existing inorganic ion concentration in hydrocarbon reservoir production wells, and uses the ions as non-partitioning water tracers. The methodology is demonstrated on a North Sea field case, using the field''s reservoir model, together with geochemical information (SO4 2−, Mg2+, K+, Ba2+, Sr2+, Ca2+ and Cl− concentrations) from the field''s producers. Based on the dataset, some of the ions are shown to behave almost as ideal seawater tracers, i.e. without sorption to the matrix, ion exchange with the matrix or scale formation with other ions in the formation water. Moreover, the dataset shows that ion concentrations in pure formation water vary according to formation. This information can be used to allocate produced water to specific water-producing zones in commingled production. Based on an evaluation of the available data, one inorganic component, SO4 2−, is used as a natural seawater tracer. Introducing SO4 2− as a natural tracer in a tracer simulation has revealed a potential for improvements of the reservoir model. By tracking the injected seawater it was possible to identify underestimated fault lengths in the reservoir model. The demonstration confirms that geochemical data are valuable additional information for reservoir characterization, and shows that integration of geochemical data into reservoir simulation procedures can improve reservoir simulation models. [Copyright &y& Elsevier]

This paper describes the measurements of the acoustic and petrophysical properties of two suites of low-shale sandstone samples from North Sea hydrocarbon reservoirs, under simulated reservoir conditions. The acoustic velocities and quality factors of the samples, saturated with different pore fluids (brine, dead oil and kerosene), were measured at a frequency of about 0.8 MHz and over a range of pressures from 5 MPa to 40 MPa. The compressional-wave velocity is strongly correlated with the shear-wave velocity in this suite of rocks. The ratio VP/ VS varies significantly with change of both pore-fluid type and differential pressure, confirming the usefulness of this parameter for seismic monitoring of producing reservoirs. The results of quality factor measurements were compared with predictions from Biot-flow and squirt-flow loss mechanisms. The results suggested that the dominating loss in these samples is due to squirt-flow of fluid between the pores of various geometries. The contribution of the Biot-flow loss mechanism to the total loss is negligible. The compressional-wave quality factor was shown to be inversely correlated with rock permeability, suggesting the possibility of using attenuation as a permeability indicator tool in low-shale, high-porosity sandstone reservoirs. [ABSTRACT FROM AUTHOR]

An automatic monitoring system has been developed to process continuously recorded microseismic data and locate the associated events. To this end we use P- and S-wave travel times and the direction of the incoming wave field. The processing is organised in four modules: (i) a multi-channel detection algorithm based on signal-to-noise ratios, (ii) a P-wave onset determination based on error prediction filtering with an auto-regressive model, (iii) a P-wave polarisation analysis providing the direction of the incoming wave field, and (iv) a rotation of seismic traces into the ray coordinate system with subsequent S-wave onset determination. For a homogeneous velocity model the event hypocenter is determined by a linearised inversion technique, and for a three-dimensional (3D) velocity model a directed grid search method or the neighbourhood algorithm is applied. We applied the monitoring system to a microseismic data set from the Ekofisk oil field in the North Sea and located about 2000 microseismic events close to the borehole receiver string. Most of the microseismic events occurred in clusters and in a depth range from 2800 to about 3050 m depth. Location errors were estimated by bootstrapping, and a comparison between results from directed grid search and neighbourhood algorithm revealed a high level of consistency. [Copyright &y& Elsevier]

Reports that the Kuqa depression bears not only plenty of natural gas, but also a large amount of condensate and small quantity of crude oil. Confirmation in this paper that, based on the geochemical correlation between the Jurassic and Triassic terrestrial hydrocarbon source rock, the natural gas in Kuqa depression belongs to coal-type gas and the main gas source rock is attributed to the middle to lower Jurassic coal series formation, while the main oil source rock is the upper Triassic lacustrine mudstone; Indication by the authors that Kuqa depression was slowly subsided in Mesozoic, but rapidly went down in Late Tertiary, which made the Jurassic and Triassic source rock suddenly deep-buried and rapidly evolved to high and over-mature phase since 5 Ma; Statement that the Triassic source rock is postponed to the Early Miocene during 23-12 Ma when entering the oil-generating peak, while the Jurassic is suspended to the latest 5 Ma, especially since 2.5 Ma to the dry gas-generating period, which is one of the characteristics of the source rock thermal evolution in Kuqa depression; Presentation in this paper of a two-stage trapping and late gas trapping model in Kuqa depression whose characteristics are: The main oil and gas reservoirs have different sources; Formation of the oil reservoir is early while the gas reservoir is formed lately; Reference to the fact that, during the early stage, it, mainly as oil, takes long distance lateral migration, while in the later stage, it, mainly as gas, takes the vertical migration and also has lateral migration; Formation of the trap formed in different time on the south and north sides of the depression and evolution into a distributional pattern with oil in the south part and gas in the north, also oil on the outer ring and gas on the inner ring; Reference in this paper to the fact that late trapping of the natural gas in Kuqa depression is favorable for the preservation of large gas fields.

Clastic reservoirs saturated with heavy oils have been observed to exhibit a marked relationship between velocity of propagation of acoustic waves and changes introduced by certain kinds of enhanced oil recovery procedures, including heating of the reservoir. This observation forms the basis for a method of monitoring the changes which occur in the reservoir when these enhanced oil recovery (EOR) procedures are used. New developments in diffraction tomographic imaging allow accurate, high-resolution images to be obtained in hydrocarbon reservoirs, clearly delineating the zones affected by these enhanced oil recovery procedures. When both compressional and shear wave data can be obtained, additional physical parameters such as Poissons ratio can be reconstructed. [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]

The article reports on the status of Multifield Geophysics' field tests in Norway. It successfully completed the tests that it deployed in May 2008 over the Peon hydrocarbon reservoir, offshore the country for its ocean bottom cable (OBC) technology. The platform uses both seismic 4C and EM sensing technology that was developed through a two year joint research and development program with its key industry partners, Wavefields Inseis, StatoilHydro Venture and the Norwegian Geotechnical Institute.