Reservoir Compartmentalization Research Articles

The value of fault analysis for field development planning

Faults play an important role in reservoir compartmentalization and can have a significant impact on recoverable volumes. A recent petroleum discovery in the Norwegian offshore sector, with an Upper Jurassic reservoir, is currently in the development planning phase. The reservoir is divided into several compartments by syndepositional faults that have not been reactivated and do not offset the petroleum-bearing sandstones completely. A comprehensive fault analysis has been conducted from core to seismic scale to assess the likely influence of faults on the production performance and recoverable volumes. The permeability of the small-scale faults from the core were analysed at high confining pressures using formation-compatible brines. These permeability measurements provide important calibration points for the fault property assessment, which was used to calculate transmissibility multipliers (TM) that were incorporated into the dynamic reservoir simulation model in order to account for the impact of faults on fluid flow. Dynamic simulation results reveal a range of more than 20% for recoverable volumes, depending on the fault property case applied and for a base case producer–injector well pattern. Fault properties are one of the key parameters that influence the range of cumulative recoverable oil volumes and the recovery efficiency.

A minimally invasive adjustable-depth blunt injector for delivery of pharmaceuticals into the posterior pole.

To investigate the feasibility and safety of a novel minimally invasive adjustable-depth blunt injector for pharmaceuticals delivery into the posterior segment. Indocyanine green (ICG), sodium fluorescein and iron oxide nanoparticles (IONPs) were injected using the new injector into the extravascular spaces of the choroid (EVSC) compartment of rabbits and cadaver pig eyes. Spectral domain optical coherence tomography (SD-OCT), fundus imaging and histology analysis were performed for assessment of injection safety and efficacy. Indocyanine green, fluorescein and IONPs were detected across the EVSC in rabbit eyes, covering over 80 per cent of the posterior eye surface. Injected IONPs were retained in the EVSC for at least 2weeks following injection. No retinal detachment, choroidal haemorrhage or inflammation was detected in any of the injected eyes. In cadaver pig eyes, ICG was detected across the EVSC. This novel minimally invasive delivery system may be used to safely deliver large volumes of pharmaceuticals into a new treatment reservoir compartment - the EVSC which can serve as a depot, in close proximity to the retina, covering most of the surface of the back of the eye without insertion of surgical instruments under the central retina. This system is predicted to enhance the therapeutic effect of treatments for posterior eye disorders.

Evaluation of reservoir compartmentalization and property trends using static modelling and sequence stratigraphy

In the context of harder-to-find reserves and rise in development costs, it is vital that reservoir heterogeneities and compartmentalization be accurately predicted ahead of the drill bit. There are many situations where unexpected compartmentalization negatively impacts reservoir development. This paper used an integration of 3D seismic, well logs, and biostratigraphic data analysis to evaluate compartmentalization in a low well density reservoir (Z-2), onshore Niger Delta. The aim was to identify areas of bypassed hydrocarbon accumulations during production due to compartmentalization. Structural modelling of the Z-2 reservoir identified three intra-reservoir faults that could lead to possible compartmentalization of the reservoir. Z-2 reservoir was interpreted as early transgressive systems tract normal regressive sediments based on sequence stratigraphic techniques used in the modelling. Z-2 reservoir is bounded below and above by layers of shale about 180–200 ft thick, which provides a good seal for the reservoir. Sequential Gaussian simulation algorithm was used to distribute the modelled petrophysical properties in the static model. Modelled porosity, permeability, and NTG ranges are 5–30 %, 1–10,000 mD, and 0.10–0.98, respectively, through all layers. Z-2 reservoir was divided into two flow units separated by approximately 12-ft-thick shale unit, which could act as a barrier to flow between the zones. Fault analysis was done using Shell structural and fault analysis plug-in in Petrel to determine the shale gauge ratio, fault permeability, and fault zone thickness of the relevant intra-reservoir faults. Fault juxtaposition analysis shows sand-on-sand juxtaposition at the fault tips. Further analysis shows that fault thickness is within the gas crossflow range of (0–0.6 ft) and shale gouge ratio for all three faults falls within the ranges of 0–100 % with a significantly higher percentage of the areas below 35 % in fault 3. Fault 1 will not allow gas crossflow, while <20 % of the juxtaposed areas in fault 2 are within the range to permit gas crossflow. Fault 3 which has a low SGR and high permeability relative to the other faults is not interpreted to be sealing. Fault zone permeability for parts of fault 1 is <1 mD while parts of faults 2 and 3 are >1 mD. The Z-2 reservoir stands the risk of being compartmentalized into two hydrocarbon accumulations (‘X’ and ‘Y’) during production. The total GIIP for Z-2 is 1668 Bscf and with the present well positions and configurations; the production of about 20 % of the GIIP is at risk of being bypassed. Future wells should be planned to appraise ‘X’ and ‘Y’ accumulations.

The Bacchus development: dealing with geological uncertainty in a small high-pressure–high-temperature development

Abstract The Bacchus Field, discovered in 2004, is a small borderline high-pressure–high-temperature (HPHT) oil field 6.8 km east of the Forties Alpha Platform. The reservoir is Fulmar Sandstone with a rotated fault-block trap. The reservoir is typically thin (10–50 m) and difficult to image seismically. Compartmentalization was anticipated due to significant in-field faulting. The Bacchus development decision was made when considerable geological uncertainty remained. The key risk-mitigation strategies employed during the development of Bacchus were to drill long horizontal wells, contacting multiple reservoir compartments, while maintaining a flexible development plan. The ability to react to unexpected results was facilitated by optimizing the development data-acquisition programme. Drilling risk and cost were minimized by exploiting existing well control for landing development wells, combined with pilot drilling in untested parts of the reservoir. Development wells were designed to be geometrically robust, minimizing the requirement for geo-steering. This ensured low wellbore tortuosity that did not compromise the completions. Bacchus was successfully developed despite the final distribution of reserves being radically different from the pre-development perception. It is argued that maintaining a flexible development plan was far more effective in maximizing the value of the Bacchus development than more extensive pre-development appraisal or modelling.

Permeability and frictional properties of halite-clay-quartz faults in marine-sediment: The role of compaction and shear

Faults in marine-sediment basins often dictate fluid flow and act as petroleum traps or seals. Permeability contrasts between these zones and the surrounding country rock can be large, depending on fault composition, stress, and strain history. Despite the importance of such faults, our understanding of their frictional properties and permeability is relatively poor. Here we report on a suite of laboratory experiments to assess the roles of fault composition, stress, and shear strain for dictating poromechanical properties of fault. Experiments were conducted at room temperature on synthetic fault gouge composed of quartz, halite, and clay (illite shale or Ca-montmorillonite). We sheared layers that were 5–7 mm thick and measured fault permeability at effective normal stresses from 2 to 6 MPa for hydrostatic conditions and after shear strains from 2 to 10. We find that fault permeability is highly sensitive to clay content, with permeabilities spanning 2–4 orders of magnitude under otherwise identical conditions. Permeability decreased up to 2 orders of magnitude with imposed shear strain >1 and ∼1 order of magnitude with increasing normal stress from 2 to 6 MPa. During shear, halite deformed via both ductile flow and brittle failure, while quartz and clay particles formed force chains that spanned the layers and defined shear localization fabrics. Samples with higher halite content exhibited greater permeability reduction, perhaps by plastic flow and pressure solution. Our results suggest that the permeability of faults in marine sediment is dictated by clay content, and that the most dramatic permeability changes occur with relatively small fault throw (shear strain from 2 to 5). This highlights the importance of understanding minor faults and fault sets when estimating subsurface fluid flow and potential reservoir compartmentalization.

Structural inversion, imbricate wedging, and out-of-sequence thrusting in the southern Junggar fold-and-thrust belt, northern Tian Shan, China

Accurate definition of structural style in subsurface interpretation is critically important for understanding the deformation history of fold-and-thrust belts, as well as assessing the petroleum prospectivity of structural traps. Using two- and three-dimensional seismic reflection surveys, well data, field mapping, forward models, and balanced cross sections, we describe the structural styles across the actively deforming southern Junggar fold-and-thrust belt in northwestern China, a basin undergoing petroleum exploration and development operations. Subsurface interpretations indicate several folds in the basin overlie Jurassic normal faults that were tectonically inverted in the Late Jurassic to Early Cretaceous. Following inversion, multiple detachment levels propagated northward from the Tian Shan and formed a series of imbricated fault-related folds. The most prominent fold trend in southern Junggar consists of the Tugulu, Manas, and Huoerguosi anticlines, which trap hydrocarbons in clastic Eocene reservoirs. These structures exhibit complex internal geometries, with coeval forethrusts and backthrusts forming imbricated structural wedges. In the latest stages of deformation, and continuing at present, the uppermost thrust sheet, the Southern Junggar Thrust (SJT), truncated the backlimbs of these structural traps, implying the SJT is a tectonically active, out-of-sequence thrust. From these interpretations, we present a model for how the southern Junggar fold-and-thrust belt developed from Jurassic to present. Moreover, we detail how fold growth, fault activity, and structural style affected charge histories, trap formation, and reservoir compartmentalization. Our results have direct implications for assessment of the southern Junggar petroleum system as well as other complex fold-and-thrust belts.

A Domain Splitting-Based Analytical Approach for Assessing Hydro-Thermo-Geomechanical Responses of Heavy-Oil Reservoirs

SummaryFor stress-sensitive heavy-oil reservoirs, geomechanical responses of the reservoir are taken into account because they play an important role in the accurate simulation of all thermal recovery techniques, such as steam-assisted gravity drainage (SAGD) or steamflood. However, full-field numerical simulations of multiphysics processes by any coupling strategies are technically impossible with current computer central processing units (CPUs). Under these conditions, analytical methods can be used as approximate techniques instead of numerical simulators because they are much faster and yet are useful tools for preliminary forecasting and sensitivity studies. In analytical models, inclusion of all flow-variable impacts into geomechanics frameworks make the equations complex and almost impossible to solve. This paper provides a flow-based domain decomposition work flow for performing different analytical coupling schemes in different reservoir compartments.Because the intensity and complexity of reservoir geomechanics vary over reservoir domain, one can divide the reservoir to some subdomains and assess different geomechanical responses separately in each subdomain. The presented analytical proxy suggests decomposition of the entire domain into two parts of “heated zone” and “wetted zone,” for rapid assessment of geomechanics. The heat-flow equation was combined with mass and momentum convective-transport equations to obtain an exact approach that correlates the saturation front of injected hot water to temperature front. The frontal velocities are dynamic interfaces for compartmentalization of the domain. In the heated zone, the total induced stresses were considered because both temperature and pressure increase, and in the wetted (saturated) zone beyond the temperature front, at each instance, the total stress induced is only a function of pressure increase, and, accordingly, stress and strain induced are caused by isotropic unloading. This technique provides a rapid estimate of geomechanical responses (stress and strain profile) in each part of the reservoir (near field and far field).A numerical model was built and implemented in CMG-STARS for a steamflood case to show the robustness and applicability range of the model. The results were analyzed for a synthetic-case single-domain model, and the model sensitivity on some reservoir parameters was checked, while geomechanical responses were not neglected anywhere (near field and far field) in the reservoir. The results of the numerical model were in close agreement with the result of the proposed analytical proxy.

Paralic reservoirs

Abstract Paralic environments, deltas, estuaries and shoreline-shelf systems respond sensitively to changes in sea-level and sediment supply, commonly by shifts in facies belts across sequence stratigraphic surfaces. As a result, they are often interleaved in highly layered successions. Layering and a wide range of associated sandbody types control the distinctive nature of paralic oil and gas fields. Layering results in stacked reservoirs. Thick extensive sandstones have structurally defined spill points, large aquifers and good reservoir properties. Such sands have high recovery, good reservoir performance and form primary completion targets. By contrast, thin, laterally restricted, isolated sandstones have low recovery factors and poor performance. Each isolated sand may have its own hydrocarbon contacts and a distinct outline that reflects both structural and stratigraphic trapping. Such sands form secondary completion targets. Fault compartmentalization is a recurring risk. Sealing faults increase the number of reservoir compartments and may decrease performance and recovery. They can also generate traps. Sedimentology is pivotal in describing heterogeneity in paralic reservoirs at all scales. Established techniques are likely to be complemented in the future by forward stratigraphic modelling, integration with palynology and more studies of surveillance data to show how sedimentological variability controls fluid movement in real reservoirs.

Time-lapse seismic monitoring of hydraulic fracture stimulations within the Niobrara-Codell Reservoir Wattenberg Field, Colorado

Time-lapse seismic interpretation is demonstrated as a viable method for observing physical modification of a tight reservoir resulting from the hydraulic fracturing process. Compressional seismic data sets were acquired before and after completions of 11 horizontal wells within a section (one-square mile) of Wattenberg Field, Colorado. The time-lapse seismic data sets, after crossequalization, showed an acoustic impedance anomaly within the reservoir interval consistent with pressurization of the reservoir from surface operations. The spatial location of the anomaly is interpreted such that pressure compartmentalization exists due to faulting within the reservoir. A decrease in the acoustic P-impedance of up to 7% was observed from the baseline to the monitor survey in the reservoir interval. An increase in pore pressure owing to hydraulic fracturing was interpreted as the physical mechanism causing the greatest change in P-impedance. Hydraulic fracturing is highly dependent on local geology, and the integration of geoscience with parameter design is necessary for optimization. Time-lapse seismic reservoir monitoring can assist in documenting fault-related reservoir compartmentalization. The Colorado School of Mines Reservoir Characterization Project (RCP) undertook a monitoring project with Anadarko Petroleum Corporation (APC) in Wattenberg Field, Colorado. The Wishbone section is a one-square mile area containing 11 horizontal wells. Each well was fractured with multiple stages and completion design was varied from stage-to-stage. The completions parameters that varied were: well spacing, targeted formation, hydraulic fracturing volumes, pressure, rates, completion type, and number of stages.

Geochemical fingerprinting of hydraulic fracturing fluids from Qusaiba Hot Shale and formation water from Paleozoic petroleum systems, Saudi Arabia

AbstractProvenance studies of produced water are essential to trace flow dynamics and reservoir compartmentalization in petroleum systems and to quantify fluid recovery rates from unconventional fracturing. Produced water from a hydraulically fractured well in the Qusaiba Hot Shale in the Northern Exploration Area, Saudi Arabia, was daily monitored and analyzed for water chemistry, and environmental (δ2H, δ13C, δ18OH2O, δ18OSO4, δ34SSO4, δ37Cl, 87Sr/86Sr) and cosmogenic isotopes (3H, 14C, 36Cl), to differentiate from reference fluids of supply water, fracturing fluids, and formation water from adjacent Paleozoic units. Initially, recovered water is composed of fracturing fluids and subsequently replaced by a homogeneous cut of pristine formation water. Formation water is composed of dominant meteoric water (approximately 84 vol%) and minor fossil evaporated seawater. The young 14C‐apparent age between 6000 and 6700 years BP and depleted δ18O/δ2H values for the meteoric component confirm the infiltration of surface water into the Qusaiba Hot Shale interval or adjacent units during the Early Holocene Pluvial Period under cooler and wetter climatic conditions than present, which suggest the presence of a very recent, dynamic hydraulic flow system. 36Cl/Cl ratios between 102 × 10−15 and 31 × 10−15 are ambiguous and can be attributed to atmospheric recharge close to the coast, mixing of 36Cl‐enriched Quaternary meteoric recharge with 36Cl‐depleted fossil seawater, and/or hypogene production by U‐Th‐enriched host rock. Produced waters from Qusaiba Hot Shale are within the compositional range of Na‐Cl‐type formation water from Paleozoic reservoir units in northern Saudi Arabia with salinities from 30 000 to 130 000 mg l−1. As a novel technological approach for exploration wells in Northern Saudi Arabia, multi‐isotopic methods were successfully implemented to quantify flowback volumes from hydraulic fracturing, and to fingerprint pristine formation water or pore water in Paleozoic systems on their provenance, residence time, migration pathways, and secondary alteration processes.

Appraising and developing ST-X field determination of uncertainties by DST analysis

A subsurface uncertainties is a possible future event, which, if occurs, would affect project objectives either negatively or positively. For any given model or event, the uncertainty is the range of variation of the component parts and possible outcomes. It could be quantified approximately by either analytical model or in a more cumbersome one such as numerical approach. This paper summarizes thedetermination ofuncertainties by DST analysis in appraising and developing the ST-X gas condensate field, which is offshore Vietnam in Block 15-1O. Drill Stem Test (DST) results show that the S field has moderate to low permeability, multiple flow boundaries/barriers, and at least 2 PVT regions. To understand the impact of these and other important reservoir parameters on ultimate gas and condensate recovery and well count, the uncertainties has to be well evaluated and understood. The study demonstrates that there is a wide range of possible ultimate gas and condensate recoveries and well counts. The top causes for this wide range are permeability and flow boundaries/barriers. In addition to the subsurface risks, drilling cost of a ST-X well is very high. The high well cost in combination with the field being offshore, having low permeability and possibly numerous reservoir compartments dramatically increase the risk of a full field development.

Diffraction imaging – a tool to reduce exploration and development risk

When evaluating exploration prospects, discoveries or a field under development it is essential to build an accurate structural framework at an appropriate scale. Detailed understanding of the fault network enables reservoir compartmentalisation risk to be better quantified at the exploration prospect stage and informs well placement optimisation in the exploration, appraisal and development phase. This paper presents a method for maximising fault information from depth migrated narrow azimuth seismic data. The faults are imaged in the depth domain by separating the diffracted component from the total migrated wavefield. We show that diffraction imaging gives higher resolution fault definition than either a conventional seismic reflectivity volume or conventional post-stack fault enhancement attributes. We also show that diffraction volumes can be further processed to generate attribute volumes with fault definition sharp enough to pick with automatic fault detection algorithms, producing a highly-detailed fault network that can augment manual fault interpretation products and be incorporated into the structural framework. Diffraction imaging is a technique for imaging small scale subsurface geological objects and discontinuities, such as faults, unconformities and karsts using the diffracted component of the total recorded wavefield.

Facies- to sandbody-scale heterogeneity in a tight-gas fluvial reservoir analog: Blackhawk Formation, Wasatch Plateau, Utah, USA

Using photomosaics and measured sections, this outcrop study characterizes facies- to sandbody-scale heterogeneity in the fluvial and coastal-plain deposits of the Blackhawk Formation of the Wasatch Plateau, Utah, USA, as an outcrop analog for the fluvial tight-gas reservoirs of the adjacent greater western Rocky Mountain basins as well as for conventional fluvial reservoirs elsewhere. Analysis on eight contiguous, vertical cliff-faces comprising both depositional-dip- and -strike-oriented segments provides field-validation and calibration of the entire range of fluvial heterogeneity, where: 1) large-scale heterogeneity (10's of m vertically and 100's of m laterally) is associated with stacking of channelized fluvial sandbodies encased within coastal-plain fines, 2) intermediate-scale heterogeneity (1's of m vertically and 10's of m laterally) is related to type and distribution of architectural elements like bar-accretion and crevasse-splay units within individual sandbodies, and 3) small-scale heterogeneity (10's of cm vertically and 1's of m laterally) is attributed to facies spatial variability within individual architectural elements.At a reservoir-scale (∼6 km strike-transect), impact of these heterogeneities has resulted in potential stratigraphic compartmentalization in varied patterns and scales within and among three zones, which have similar lateral extents. Distinct vertical or lateral compartmentalization, contrasting net-to-gross pattern, width-constraint by either large- or intermediate-scale heterogeneity, disparity in communication between principal reservoir compartments by intermediate-scale heterogeneity, and reservoir-quality segregation to barrier styles rendered by small-scale heterogeneity are documented in an array of trends. These intriguing trends are challenging to correlate across the reservoir-scale dataset, contributing to multiple, analogous exploration and production uncertainties. For improved tight-gas exploration and production strategy of the western Rocky Mountain basins, study results were also used in developing potential predictive tools: 1) thickness threshold of individual channelized sandbody favoring multiple well intersection, 2) aspect ratio in performing probabilistic sandbody-width estimation, and 3) prediction of sandbody amalgamation using underlying coal thickness.

Hydraulic properties of fault zones in porous carbonates, examples from central and southern Italy

We present the results of in situ permeability measurements performed, using a portable field permeameter, on normal and strikeslip fault zones that crosscut high-porosity carbonate grainstones. The measurement sites expose in the Cretaceous Orfento Formation of the Majella Mountain (Abruzzo, Italy), and the Lower Pleistocene deposits of the Favignana Island (Sicily, Italy). Nine small-displacement, compactive shear banding-based fault zones have been tested in the field. The fault offset ranges between 10 and 200 centimeters. The acquired permeability data indicate a two orders of magnitude decrease of porosity and permeability from the host rock to the cataclastic fault cores. A clear dependence of the fluid circulation paths through porous carbonates is therefore inferred at depth due to orientation, density and connectivity of the fault zones. Moreover, this study indicates the key role played by the pore network characteristics (pore dimensions above all) of undeformed host rocks on determining extremely different permeability values of the faulted porous carbonate grainstones. Accordingly, the results presented in this study may be helpful in applications such as geofluids management for improving the forecasting of carbonate reservoir quality and understanding the extent of reservoir compartmentalization.

Interpretation of wrench faulting and faultrelated pressure compartmentalization, Wattenberg Field, Denver Basin Colorado

A structural interpretation of a 128 km2 3D seismic data set from Wattenberg Field, Colorado indicates a northeast-trending step-over fault system in the Niobrara Formation. These step-over faults are the product of a fault block rotation that is caused by two large-scale dextral wrench faults: the Longmont and the Lafayette wrench fault zones. An investigation into different fault orientations between the Niobrara and the overlying Pierre Shale indicates that a rotation of the maximum horizontal stress has occurred during the Laramide Orogeny. The step-over faults and stress rotation result in reservoir compartmentalization in the Niobrara. Seismic inversion shows the different stress field compartmentalization. Low impedance occurs in a lower effective stress environment caused by high pore pressure. These compartments may constitute ‘sweet spots’ in exploration and production in the Niobrara Formation. The Niobrara Formation is a major hydrocarbon reservoir deposited during the Late Cretaceous (Figure 1a). This formation consists of the Smoky Hill Member and Fort Hays Limestone. The Smoky Hill member consists of A, B, and C chalks, and A, B, and C marls. Bratton (unpublished work, 2015) indicates that the overpressure regime extends into the overlying Sharon Springs Member of the Lower Pierre Formation. Figure 1B shows the geologic events of the Late Cretaceous Petroleum System (Higley and Cox, 2007). The Laramide Orogeny occurred during the Late Cretaceous and Early Tertiary (between 70-50 ma.). This event is thought to be responsible for the structural features in the study area (Higley and Cox, 2007). The products of this movement include several wrench fault zones located in the area mapped by Weimer (1996).

Heterogeneities and Intra Sand-Body Compartmentalization in Late Oligocene Delta-Front Deposit, Niger Delta, Nigeria

This paper presents the study of the heterogeneity in lithofacies, porosity, permeability, mineral grain density, pore-throats sizes and hydraulic rock types and the intra sand-body compartmentalization in cored delta-front deposit of Greater Ughelli depobelt of Niger Delta. Sedimentological study of core samples results in the identification of nine lithofacies and the interpretation of environments of deposition as mainly proximal and distal delta-front mouth bar. The sand unit indicates moderate to excellent reservoir quality with core porosity between 16.2 and 29.5% and permeability between 16.8 and 7,560 md. Dykstra-Parsons core permeability distribution coefficient of 0.97 indicates that the studied reservoir sand-body is vertically highly heterogeneous, with high potential for vertical intra sand-body compartmentalization. Graphical cluster analysis of Flow Zone Indicators (FZI) led to the identification of nine Hydraulic Flow Units (HFU) with distribution controlled by depositional facies. The prediction of permeability, porethroats (r35) and flow zone indicator values of the reservoir in an uncored-well using predictive mathematical models developed with multiple regression analysis enabled the inter-well correlation of hydraulic flow units and indicates lateral continuity of reservoir compartments. An intra sand-body compartmentalization evaluated with core permeability values, Winland r35 coefficients and flow zone indicators was corroborated with formation pressure data analysis. Results show that the studied delta front-mouth bar reservoir is vertically compartmentalized by intercalated shales. Fractures in over-pressured zones were found to reduce vertical reservoir fluid compartmentalization by intercalated shales. However, reduction in reservoir pressure due to hydrocarbon production can result in dynamic compartmentalization and consequently, reduction in hydrocarbon recovery.

Enhanced delineation of reservoir compartmentalization from advanced Pre and Post-stack seismic attribute analysis

SUMMARY Reservoir compartmentalization has a huge bearing on fluid flow within hydrocarbon reservoirs, and can impact overall recovery during field development. Small and subseismic faults can have a dramatic effect on the compartmentalization within a reservoir, but until recently they have not typically been incorporated into fault interpretations. This can be due to data fidelity and the amount of time needed to manually pick them. Their omission from the interpretation – and ultimately reservoir models – means the understanding of reservoir compartmentalization is incomplete, hence solving this problem is critical to improve production. Approaches that automatically identify and extract faults from seismic volumes are available. These automated methods aim to emphasize discontinuities within seismic volumes and are usually focused on poststack data. However, they need preconditioned inputs that are often based around a coherence algorithm. This preconditioning aims to suppress noise but can inflict data degradation, which may diminish smaller features in the seismic volumes. This article proposes an enhanced approach using a new combination of preconditioning steps designed to avoid these degradation problems. It also proposes the use of prestack seismic data, which has not traditionally been used for this purpose. Analysis of various pre-stack elements is displayed to show it can delineate more features than poststack data alone in certain noisy areas, such as gas effects or low frequencies. Finally, it demonstrates that the best approach combines results from pre- and poststack analysis to produce a more complete picture of reservoir compartmentalization.

Intra- and inter-field compositional changes of oils from the Misoa B4 reservoir in the Ceuta Southeast Area (Lake Maracaibo, Venezuela)

Here we analyzed oil samples from 35 wells in the Ceuta Southeast Area (Lake Maracaibo Basin, northwestern Venezuela) in order to evaluate lateral intra-reservoir continuity in the Misoa B4 unit. Biomarkers, isotopic signature, and also V and Ni were examined using gas chromatography–mass spectrometry (GC–MS), isotope ratio mass spectrometry (IRMS), and inductively-coupled plasma atomic emission spectroscopy (ICP-AES). Multivariate statistical analysis was also applied to obtain useful information from geochemical data. On the basis of the characterization of these samples, we conclude that they all fall into various oil families derived from two pulses of hydrocarbon generation, migration and accumulation from the calcareous La Luna source rock, deposited in an anoxic marine environment under reducing conditions. Thus, these oils are a mixture of an earlier biodegraded, less mature oil charge and a later fresh non-biodegraded oil recharge. In addition, we applied asphaltene pyrolysis to one (LG-62) of the three “anomalous” oils. The LG-62 sample was confirmed as an almost “pure” paleobiodegraded end-member, whereas the VLF-3020 oil was tentatively classified as the unaltered end-member oil-type. Finally, the GC fingerprints and Fourier Transform Infra Red (FTIR) spectroscopic indices of the oils were used to detect minor variations in composition that are indicative of reservoir compartmentalization.

Large-Scale $$\hbox {CO}_2$$ CO 2 Storage in a Deep Saline Aquifer: Uncertainties in Predictions Due to Spatial Variability of Flow Parameters and Their Modeling

Scarce data and uncertainties in the spatial variation of geological properties lead to different possible models of these heterogeneities. The aim of this study is to compare the pressure results and $$\hbox {CO}_2$$ behavior of different permeability field models for a large-scale $$\hbox {CO}_2$$ injection in a deep saline aquifer. Five ways of representing heterogeneities are tested and compared. The simplest representation defines homogeneous equivalent properties over the entire domain. A second representation is obtained by considering homogeneous layers. Two other models represent the lateral and vertical variations in permeability in greater detail by geostatistical methods with either a continuous model or a discontinuous model (discrete values). The last model is the semi-homogeneous model combining a heterogeneous area and a homogeneous area depending on the complexity of the flow process. Highly variable predictions arise from the heterogeneities, and significant differences in estimates are obtained using the various modeling methods. The optimum resolution depends on the type of response to be estimated. Averaged properties at large scale are not adequate to estimate the critical pressure propagation far from the well. Averaged properties in the injection area are not sufficient to assess the maximum increase in pressure or the extent of $$\hbox {CO}_2$$ migration. Lateral and vertical connectivities, and reservoir compartmentalization modeling are required to obtain reliable results. But the resolution requirements are not to be at the finest scale: The discontinuous model (discrete values) gives satisfactory results compared to the continuous model. The way to represent spatial variability of porosity and pore compressibility is also studied. The influence of these two properties is far lower than that of permeability.

Epidemiological and evolutionary management of plant resistance: optimizing the deployment of cultivar mixtures in time and space in agricultural landscapes.

The management of genes conferring resistance to plant–pathogens should make it possible to control epidemics (epidemiological perspective) and preserve resistance durability (evolutionary perspective). Resistant and susceptible cultivars must be strategically associated according to the principles of cultivar mixture (within a season) and rotation (between seasons). We explored these questions by modeling the evolutionary and epidemiological processes shaping the dynamics of a pathogen population in a landscape composed of a seasonal cultivated compartment and a reservoir compartment hosting pathogen year-round. Optimal deployment strategies depended mostly on the molecular basis of plant–pathogen interactions and on the agro-ecological context before resistance deployment, particularly epidemic intensity and landscape connectivity. Mixtures were much more efficient in landscapes in which between-field infections and infections originating from the reservoir were more prevalent than within-field infections. Resistance genes requiring two mutations of the pathogen avirulence gene to be broken down, rather than one, were particularly useful when infections from the reservoir predominated. Combining mixture and rotation principles were better than the use of the same mixture each season as (i) they controlled epidemics more effectively in situations in which within-field infections or infections from the reservoir were frequent and (ii) they fulfilled the epidemiological and evolutionary perspectives.