Shale Drapes Research Articles

Shaking and splashing—A case study of far‐field effects of the Mjølnir asteroid impact on depositional environments in the Barents Sea

AbstractThe Mjølnir impact crater in the Norwegian Barents Sea features among the 20 largest impact craters listed in the Earth Impact Database. The impact is dated to 142 ± 2.6 Ma, corresponding closely to the Jurassic/Cretaceous boundary in the Boreal stratigraphy. Multidisciplinary studies carried out over the last three decades have suggested that the up to 40 km wide crater was created by a 1–3 km diameter impactor colliding with a shallow epicontinental sea, causing regional havoc and a regional ecological crisis that followed in its wake. Only minor evidence for the consequences of the impact for the surrounding depositional basins has been documented so far. This study describes a large submarine slump penetrated by hydrocarbon exploration well 7121/9‐1, located in the southern Hammerfest Basin and approximately 350 km away from the impact site. The slump is dated by a black shale drape, which contains characteristic impact‐related biotic assemblages and potential ejecta material. This precise dating enables us to associate the slump with large‐scale fault movements and footwall collapse along the basin‐bounding Troms‐Finnmark Fault Complex, which we conclude were caused by shock waves from the Mjølnir impact and the passage of associated tsunami trains. The draping black shale is interpreted to represent significant reworking of material from the contemporary seabed by tsunamis and currents set up by the impact.

Geologic Modeling and Ensemble-Based History Matching for Evaluating CO2 Sequestration Potential in Point bar Reservoirs

The target reservoirs in many CO2 projects exhibit point bar geology characterized by the presence of shale drapes that act as barriers preventing the leakage of CO2. However, the extent of the flow barriers can also impede the displacement of CO2 in such reservoirs and restrict the storage volume. Therefore, developing a framework for modeling point bars and their associated heterogeneities is crucial. Yet, for the point bar model to be geologically realistic and reliable for evaluating CO2 sequestration potential, it should be calibrated to reflect historical data (e.g., CO2 injection data). This study is therefore in two parts. The first part focusses on the modeling of point bar heterogeneities (i.e., lateral accretions and inclined heterolithic stratifications). To ensure that the heterogeneities are preserved, we implemented a gridding scheme that generates curvilinear grids representative of the point bar curvilinear geometry. We subsequently incorporated a grid transformation scheme to facilitate geostatistical modeling of reservoir property distributions. The second part of this study is a model calibration step, where the point bar model is updated by assimilating CO2 injection data, in an ensemble framework. Ensemble-Kalman Filter was used first to update ensembles of point bar geometries, to select the geometry that yields the closest match to observed data. Within this geometry, indicator-based ensemble data assimilation was used to perform updates to the ensemble of point bar permeability models. The indicator approach overcomes the Gaussian limitation of the traditional ensemble Kalman filter. The workflow was run on the Cranfield, Mississippi CO2 injection dataset. It was observed, after model calibration, that the final updated ensemble of models yields a reasonable match with the historical data. The updated models were run in a forecast mode to predict the long-term CO2 sequestration potential of the Cranfield point bar reservoir. Results demonstrate that 1) preserving the heterogeneities in the point bar modeling process, and 2) constraining the point bar model to historical data (e.g., CO2 injection data) are essential for accurately evaluating the CO2 sequestration potential in point bar reservoirs.

A hierarchical stochastic modeling approach for representing point bar geometries and petrophysical property variations

The flow of fluids in point bars is affected by the existence of heterogeneities like shale drapes that are found on the surfaces of inclined heterolithic stratifications. In fact, these shale drapes can act as fluid flow baffles; therefore, developing a framework for modeling point bars and their associated heterogeneities is vital. In this study, a stochastic process-based modeling approach is presented for capturing the main point bar heterogeneities: accretion surfaces (i.e., the aerial heterogeneity) and inclined heterolithic stratifications (i.e., the vertical heterogeneity). The former was modeled using a sine-generation function and the latter, with a sigmoidal function after which they were combined into a 3D point bar model. To ensure proper modeling of petrophysical properties, we developed a more representative gridding scheme which generates curvilinear grids representative of the point bar geometry. This grid was then transformed into a rectilinear grid to allow for geostatistical simulation after which all petrophysical properties were mapped back into the original curvilinear grid. An essential element of this modeling approach is the stochastic representation of shale drapes at the interface between successive accretion surfaces. The workflow was tested using a real field dataset for the Cranfield field, Mississippi. The constructed model was then subjected to a flow simulation study mimicking a CO2 storage scenario. Various sensitivities were simulated to evaluate the effect of heterogeneities on CO2 flow within the point-bar. Results demonstrate the importance of representing point-bar related heterogeneity and the spatial distribution of shale drapes on CO2 plume migration and storage.

3D modeling of deepwater turbidite lobes: a review of the research status and progress

Deepwater turbidite lobe reservoirs have massive hydrocarbon potential and represent one of the most promising exploration targets for hydrocarbon industry. Key elements of turbidite lobes internal heterogeneity include the architectural hierarchy and complex amalgamations at each hierarchical level leading to the complex distribution of shale drapes. Due to limitation of data, to build models realistically honoring the reservoir architecture provides an effective way to reduce risk and improve hydrocarbon recovery. A variety of modeling techniques on turbidite lobes exist and can be broadly grouped into pixel-based, process-based, process-oriented, surface-based, object-based and a hybrid approach of two or more of these methods. The rationale and working process of methods is reviewed, along with their pros and cons. In terms of geological realism, object-based models can capture the most realistic architectures, including the multiple hierarchy and the amalgamations at different hierarchical levels. In terms of data conditioning, pixel-based and multiple-point statistics methods could honor the input data to the best degree. In practical, different methods should be adopted depending on the goal of the project. Such a review could improve the understanding of existing modeling methods on turbidite lobes and could benefit the hydrocarbon exploration activities of such reservoirs in offshore China.

Simplified Dynamic Modeling of Faulted Turbidite Reservoirs: A Deep-Learning Approach to Recovery-Factor Forecasting for Exploration

Summary Faults are geological features that are essential in considering the development of hydrocarbon reservoirs. Significant resources (appraisal costs and manpower) are often deployed to locate them and assess their connectivity more accurately so that adequate investment decisions can be made. Early in a project's life, data might be sparse or the time that can be dedicated to data processing might be limited. An estimate of the impact of faults can be derived by considering the impact of analogous fault patterns in similar reservoir environments. A significant number of discoveries consist of channelized turbidite reservoirs draped over deepwater toe–thrust anticlines. To understand the effects of various fault patterns on the recovery factors of structurally complex turbidite reservoirs, we first perform extensive flow–simulation–based multidimensional sensitivity studies using realistic channelized stratigraphic architectures. Many of these reservoirs contain high–porosity, high–permeability channels, light oil, limited aquifer drive, and a limited number of fault populations. To constrain the potential impacts of the faults, a generic reservoir model was constructed and simulated with varying reservoir and fault properties. Because the input parameters are known (e.g., fault–zone thickness and permeability, shale–drape coverage, and oil viscosity), the relative importance of each variable can be quantified. The simulation results show that the impacts of the faults on reservoir performance vary systematically with the fault length and orientation, the undeformed–reservoir permeability, and the fault permeability. The recovery factors are relatively insensitive to fault–zone thickness, net/gross ratio, and porosity. The time–delay effect of the faults is significant in reservoirs with a permeability of approximately 100 md but not in darcy–quality reservoirs. In most fault scenarios, the recovery factors from simulations with high–permeability faults range from approximately 30% in 100–md reservoirs to approximately 45% in 3,000–md reservoirs, equivalent to 75 to 96% of the recovery factors of the unfaulted reservoirs. In comparison, assuming the most likely fault permeabilities, the recovery factors decrease to circa 20% in 100–md reservoirs and circa 41% in 3,000–md reservoirs, equivalent to 40 to 85% of the values in unfaulted reservoirs. To learn and predict the effects of faults on the recovery factor in a very fast and reasonably generic fashion in deepwater toe–thrust anticlines, we have developed an accurate deep–learning (DL) based surrogate model that predicts the structure connectivity factors as a function of recovery time. These factors are then used for discounting the recovery factors computed by simpler and easier–to–construct unfaulted models. The surrogate model is a very fast and advanced proxy for the multidimensional structure connectivity factor function and operates without resorting to any new flow simulation with a faulted model. We describe the novel DL architecture used for constructing the surrogate model and quantitatively prove its effectiveness. We finally demonstrate an example real–life application of the surrogate model on an exploration–stage prospect–ranking exercise.

Analyzing the architecture of point bar of meandering fluvial river using ground penetration radar: A case study from Hulun Lake Depression, China

The point bar is one of the most important reservoirs in a meandering depositional system, and accurately building a 3D architecture model for point bars is crucial to predict hydrocarbon distribution within the reservoir. Unfortunately, we can only obtain a qualitative description about the internal architecture of the point bar due to the limited information or the low resolution of available data (such as reflection seismic data). To build a 3D prototype point bar reservoir model, we analyze the architecture of point bars by integrating high-resolution ground penetrating radar (GPR) data and modern deposition. We found that our GPR data have five main reflection patterns (GPR facies), and GPR facies can be used to relate with architectural elements (the depositional facies and geobodies within depositional facies). The concave-down GPR facies is usually related to the abandoned channel. The continuous, subhorizontal, subparallel GPR facies is commonly related with lateral-accretion sand bodies within the point bar. The multiple stacked small-scale, discontinuous reflections GPR facies is interpreted to be shale drapes within the point bar. We further analyzed the geometry parameters of the identified channels. We found that the nonsymmetric [Formula: see text] of abandoned channel near the channel axis is related to the ratio between the curvature of channel radius [Formula: see text] and channel width [Formula: see text] ([Formula: see text]). Finally, we built two 3D channel reservoir models and our models could provide useful guidance for the architecture analysis of buried meandering fluvial reservoirs.

THE INACCURACY OF INTERPOLATION AT THE CONSTRUCTION OF BOUNDARIES ON THE ENGINEERING GEOLOGICAL SOIL PROFILES FOR THE GENERATION OF CALCULATED MODELS OF GEOLOGICAL MEDIUM

On the basis of the recent data, construction accuracy of geological boundaries on engineering geological soil profiles is studied. The concept of the interpolation error of geological boundaries is introduced. This error inevitably presents in all engineering geological soil profiles, as well as in hydrogeological and other geological soil profiles. The error is caused by uncertainty of the state of geological boundary between the wells. Geologists draw the line on the basis of the hypothesis about its genesis. The hypothesis is being checked at the next stage of the investigations, or at the opening of the foundation pit, or already during the examination of the accident. The interpolation error fundamentally influences the character of the engineering geological model of the geological medium, and through this, it influences the quality of the system’s calculation of the building-base. The article proposes methods for defining the interpolation error, based on the study of existing engineering geological soil profiles and outcrops of rocks. Using the example of analysis of engineering geological soil profiles for investigations’ objects located in the south-west of Moscow and the south of the Nizhny Novgorod region, it is shown that the interpolation error for the bottom of technogenetics soils and the shale drapes can reach 1 meter with a distance between wells of less than 40 meters and much more than 1 meter at the interwell spacing is 100 meters. Such inaccuracies in engineering geological information lead to an inaccuracy in the settlement calculation of the building exceeding 50% of the calculated value. The article presents, on the basis of mathematical-statistical analysis, the values of the interpolation error for seven geological boundaries of a different genetic type. The specified scientific and technical problem of assessing the accuracy of engineering geological survey information, in terms of the geometry of the engineering geological model of the geological medium, requires further research and reflection in normative documents, in particular in SP 47.13330.2016 « SNiP 11- 02-96 Engineering surveys for construction. Fundamentals », from which the table 6.2, which existed in previous editions of the document and was aimed at increasing the accuracy of geological soil profiles, are excluded.

Analysis and modeling of fluvial-reservoir petrophysical heterogeneity based on sealed coring wells and their test data, Guantao Formation, Shengli oilfield

The aim of this study is to analyze relationships between lithological heterogeneity and petrophysical properties in fluvial features of the Guantao Formation (Miocene) in view of reservoir water flooding in the Shengli oilfield (Shandong Province, RPC). Black oil simulation models of intermediate scale elements such as point bars and their lateral accretion beds. Using analysis assay data from sealed coring wells demonstrates permeability, rather than porosity, as the determining constraining parameter.The Guantao formation consists of fluvial deposits of braided and meandering river. In the Shengli Oil Field, the target layer of Ng52+3 is mainly composed of well-sorted fine-grain sandstone, and it mainly develops in-channel point bars which are characterized by lateral accretion with graded sand-shale beds showing notable variations in porosity and permeability.Dense well spacing sections were used to identify geometric architectural parameters of the subsurface sandstone interpreted as fluvial point bars. These parameters were used to build the model of the point-bar stratigraphic framework, accurately reflecting the Guantao Formation channel-fill architecture. An exponential function was used to reconstruct the permeability model of intermediate-scale elements and lateral-accretion beds in contrast with models constrained by porosity and shale drapes.Analysis assay data of sealed coring wells indicate that porosity does not display obvious changes in the main body part of point-bar sandstone, and porosity has less obvious correlations with permeability and grain size. The grain size of sandstone exhibits regular variation in intermediate-scale depositional elements and lateral-accretion beds. Vertically, the change of permeability presents exponential functions in the same intermediate-scale element and lateral-accretion bed.Two- and three-dimensional (2-D and 3-D) models and black-oil simulations compare scenarios based on different lithologies, shale drapes, observed grain-size trends, petrophysical properties, and modeling methods. Affected by the shape features of lateral-accretion interfaces, the enrichment areas of remaining oil obviously exhibit morphological characteristics of the echelon. There is little difference in breakthrough time between the “shale drapes” model using porosity as constraint and that using the permeability-distribution function as constraint, but the recovery percentage of the latter model is obviously lower than that of the former. The model in which lateral-accretion beds and units were modeled with the permeability-distribution function as the constraint is about 6% lower than the “shale drapes” model constrained by porosity in recovery percent after 10 years. From the development effect, the injection-production method in which the water-flooding direction is along the dip direction of lateral-accretion surfaces is a little better than that in which the water-flooding direction is opposite to the dip direction of intersurfaces.

Quantitative characterization of shales within tidally influenced fluvial valley fill deposits of the Ferron Sandstone, eastern Utah: Implications for hydrocarbon exploration

This study evaluates the proportion, length, and effective properties of thin (0.003 - 0.7 m [0.01 – 2.3 ft.]) shale beds and drapes in tidally-influenced channels within a compound valley fill with a focus on estimating geologically-based effective rock properties. The Cretaceous Ferron Sandstone is an outcrop analog for fluvial-tidal systems with primary reservoirs being deposited as tidally-influenced valley filling point bars. The study outcrops expose three valley systems in Neilson Wash of Utah. Light detection and ranging derived digital outcrop models have been used to characterize shale length, width, thickness and frequency of each valley fill succession. Long, uncommon, and anisotropic shales in Valley-1 (V1) were deposited in a braided setting with little tidal influence. In contrast, shales in Valley-2 (V2) were abundant, short, common, and equidimensional suggesting deposition by more tidally-influenced meandering rivers. Short, frequent, and equidimensional shales in Valley-3 (V3) were deposited in single-thread meandering rivers with less tidal influence. A sandstone-shale model was utilized to estimate the effects of shales on vertical to horizontal permeability ratio (kv/kh). The unique character of each depositional unit was reflected in resultant kv/kh distributions. The valley fill deposits, V1, V2, and V3 had an average kv/kh ratio of 0.11, 0.09 and 0.17, respectively. More tidally-influenced reservoirs such as the studied V2 had short, but frequent shales which resulted in low kv/kh estimates. Estimates of kv/kh for valleys that predominantly contained fluvial point bar deposits with lesser tidal influence (V1 and V3) were higher. The results of this study highlight the link between shale heterogeneity, reservoir architecture, and inferred flow parameters.

Quasiglobal Multiphase Upscaling of Reservoir Models With Nonlocal Stratigraphic Heterogeneities

Summary Representing the complete spectrum of fine-scale stratigraphic details in full-field dynamic models of geologically complex clastic reservoirs is beyond the limits of existing computational capabilities. A quasiglobal multiphase upscaling method—the regional-scale multiphase upscaling (RMU) method—is developed, in which the dynamic effects of subgrid-scale (typically subseismic) nonlocal stratigraphic reservoir elements (e.g., channels, lobes, sand bars, and shale drapes) are captured by means of pseudofunctions for flow simulation. Unlike conventional dynamic multiphase upscaling methods, the RMU method does not require fine-resolution reservoir-scale simulations. Rather, it relies on intermediate-scale sector-model simulations for pseudoization. The intermediate scale, also referred to as the regional scale, is defined as the spatial scale at which the global multiphase flow effects of nonlocal stratigraphic elements can be approximated by fine-resolution flow simulations with reasonable accuracy. During the pseudoization process, dynamic multiphase flow responses of coarse regional-scale sector models are calibrated against those stemming from their corresponding fine-resolution parent models. Each regional-scale sector model is simulated only once at the fine geologic resolution. The process involves automatic determination and subsequent modification of the parameters that describe rock relative permeability and capillary pressure functions. Coarse regional-scale models are simulated a few times until a reasonable match between their coarse- and fine-resolution dynamic responses can be attained. The parameter-estimation step of the pseudoization process is performed by use of a very efficient constrained nonlinear optimization algorithm. The RMU method is evaluated in two proof-of-concept numerical examples involving a plethora of turbidite stratigraphic architectures. The method yields simulation results that are always more accurate than conventionally upscaled coarse-resolution model predictions. Incorporating geologically based pseudofunctions into otherwise simple coarse-resolution full-field reservoir models reduces the simulation cycle time significantly and improves the accuracy of production forecasts. The RMU method typically delivers two to three orders of magnitude in speed up of flow simulations.

Dynamic impact and flow-based upscaling of the estuarine point-bar stratigraphic architecture

Abstract The estuarine point-bar architecture – one of the main sub-depositional environments of tide-dominated shallow-marine and fluvial (SM&F) systems – constitutes one of the most shale-prone clastic reservoir architectures potentially posing risks to the production performance. A set of simulation-based sensitivity studies quantify the effects of a number of stratigraphic and reservoir engineering parameters on the dynamic connectivity of the confined estuarine point-bar architecture. Water injection recovery mechanism is utilized for polarizing the stratigraphic and reservoir engineering parameters in terms of their effects on hydrocarbon recovery. The point-bar shale-drape architecture and abandonment channel attributes (e.g., permeability, facies composition, and shale-drape coverage) dominate the dynamic reservoir connectivity, hence the recovery factor and water breakthrough time/profile. In terms of reservoir engineering parameters, well spacing and, to some degree, relative mobility ratio constitute the factors of importance for the investigated model parameter ranges. The dynamic effects of intra-facies permeability heterogeneity are evaluated using a number of realizations comparing them to those stemming from facieswise-homogeneous realizations. Results indicate that intra-facies permeability heterogeneity influences the connectivity factor for low shale-drape coverage levels. For high coverage levels, presence of shale drapes almost completely overshadows the influences of intra-facies permeability heterogeneity. A novel multiphase flow-based upscaling method, specifically developed for clastic reservoirs containing long-correlation-length permeability heterogeneity, is evaluated first-time on the scale-up of the estuarine point-bar architecture. Resulting coarse-scale models capture the fine-scale dynamic behavior with an accuracy level that is significantly higher than those obtained by use of single-phase flow-based upscaling.

Shale-Drape Modeling for the Geologically Consistent Simulation of Clastic Reservoirs

SummaryA set of algorithms, called the shale-drape function (SDF), has been developed that incorporates bounding shales (shale drapes) for channels, channel belts (also known as meander belts), lobes and lobe complexes in 3D geologic models used for reservoir simulation. Shale drapes can have a significant impact on the recovery efficiency of clastic reservoirs. Therefore, they need to be modeled when present in significant quantities (in general, more than 50 to 70% in terms of areal coverage). The function incorporates shale drapes into a geologic model with an iterative process that creates shale layers over the entire surface of reservoir objects and then places ellipsoid-shaped holes into shale surfaces until a desired areal coverage is reached. The workflow for application recommends to grid the simulation model along the boundaries of stratigraphic objects, thereby ensuring that the shales can be realistically represented in the fine-scale geomodel and preserved in the post-upscaling simulation model.

Facies Architecture and Stratigraphic Evolution of A River-Dominated Delta Front, Turonian Ferron Sandstone, Utah, U.S.A

Abstract Facies architectural analysis of a river-dominated deltaic parasequence in the Turonian Ferron Sandstone Member, near Factory Butte, Utah, was conducted to determine the hierarchical spatial arrangement of mouth bars and their role in constructing the delta. Five architectural elements were identified using 21 measured sections, paleocurrent measurements, and bedding diagrams. They are: (1) prodelta (PF), (2) frontal splay (FS), (3) detached distal bars (DBs), (4) distributary mouth bars (DMBs), and (5) terminal distributary channels (TDCs). Lower in the parasequence, detached bars consist of proximally located cross-bedded and quasi-parallel laminated subaqueous bars that onlap the delta-front slope and grade distally into finer-grained distal delta front splays. These bars translate downstream in a progradational–aggradational–degradational trajectory and are overlapped by adjacent bars, forming a bar assemblage. These bars are interpreted to have been deposited by descending hyperpycnal flows as a decelerating axial jet. Deposition of these bars occurs at the delta-front to prodelta chokepoint, presumably due to flow deceleration. The distal bar assemblage is capped by an extensive but discontinuous shale drape, suggesting local abandonment. Upper facies assemblages show a distinct switch to predominantly cross-bedded distributary mouth bars, corresponding to a decrease in water depth, an increase in friction, and a likely transition into planar versus axial jets. This is indicated by aggrading cross-bedded distributary mouth bars that overlie the distal bars. Laterally, the mouth-bar deposits are interstratified with terminal distributary-channel deposits with prominent scour surfaces at the base. Separate distributary channels and their bars coalesce, ultimately to build the entire delta lobe. The detached distal bars prograde locally west to northwest and lack fair-weather wave-formed sedimentary structures, suggesting a local embayment along the regionally northeast prograding shoreline. Low levels of ichnofaunal diversity indicate a stressed, river-dominated setting. At the base of the section, frontal splays and detached bars, dominated by storm-driven river-flood deposits, are deposited over muddy prodelta facies. Detached bars are likely initiated about 500 meters distal of the distributary channel, in water depths of ∼ 10–30 meters, based on the thickness of the parasequence. Once this subaqueous platform is constructed by the distal bar assemblage, more proximal distributary mouth bars fill the remaining shallow-water accommodation. As the system continues to shallow, distributary channels override and scour the bars, reflecting reduced accommodation.

Upper Miocene to Quaternary unidirectionally migrating deep-water channels in the Pearl River Mouth Basin, northern South China Sea

A series of short and steep unidirectionally migrating deep-water channels, which are typically without levees and migrate progressively northeastward, are identified in the Baiyun depression, Pearl River Mouth Basin. Using three-dimensional seismic and well data, the current study documents their morphology, internal architecture, and depositional history, and discusses the distribution and depositional controls on the bottom current–reworked sands within these channels. Unidirectionally migrating deep-water channels consist of different channel-complex sets (CCSs) that are, overall, short and steep, and their northeastern walls are, overall, steeper than their southwestern counterparts. Within each CCS, bottom current–reworked sands in the lower part grade upward into muddy slumps and debris-flow deposits and, finally, into shale drapes. Three stages of CCSs development are recognized: (1) the early lowstand incision stage, during which intense gravity and/or turbidity flows versus relatively weak along-slope bottom currents of the North Pacific intermediate water (NPIW-BCs) resulted in basal erosional bounding surfaces and limited bottom current–reworked sands; (2) the late lowstand lateral-migration and active-fill stage, with gradual CCS widening and progressively northeastward migration, characterized by reworking of gravity- and/or turbidity-flow deposits by vigorous NPIW-BCs and the CCSs being mainly filled by bottom current–reworked sands and limited slumps and debris-flow deposits; and (3) the transgression abandonment stage, characterized by the termination of the gravity and/or turbidity flows and the CCSs being widely draped by marine shales. These three stages repeated through time, leading to the generation of unidirectionally migrating deep-water channels. The distribution of the bottom current–reworked sands varies both spatially and temporally. Spatially, these sands mainly accumulate along the axis of the unidirectionally migrating deep-water channels and are preferentially deposited to the side toward which the channels migrated. Temporally, these sands mainly accumulated during the late lowstand lateral-migration and active-fill stage. The bottom current–reworked sands developed under the combined action of gravity and/or turbidity flows and along-slope bottom currents of NPIW-BCs. Other factors, including relative sea level fluctuations, sediment supply, and slope configurations, also affected the formation and distribution of these sands. The proposed distribution pattern of the bottom current–reworked sands has practical implications for predicting reservoir occurrence and distribution in bottom current–related channels.

The impact of fine-scale turbidite channel architecture on deep-water reservoir performance

This article concentrates on the question, Which parameters govern recovery factor (RF) behavior in channelized turbidite reservoirs? The objective is to provide guidelines for the static and dynamic modeling of coarse reservoir-scale models by providing a ranking of the investigated geologic and reservoir engineering parameters based on their relative impact on RF. Once high-importance (H) parameters are understood, then one can incorporate them into static and dynamic models by placing them explicitly into the geologic model. Alternatively, one can choose to represent their effects using effective properties (e.g., pseudorelative permeabilities). More than 1700 flow simulations were performed on geologically realistic three-dimensional sector models at outcrop-scale resolution. Waterflooding, gas injection, and depletion scenarios were simulated for each geologic realization. Geologic and reservoir engineering parameters are grouped based on their impact on RF into H, intermediate-importance (M), and low-importance (L) categories. The results show that, in turbidite channel reservoirs, dynamic performance is governed by architectural parameters such as channel width, net-to-gross, and degree of amalgamation, and parameters that describe the distribution of shale drapes, particularly along the base of channel elements. The conclusions of our study are restricted to light oils and relatively high-permeability channelized turbidite reservoirs. The knowledge developed in our extensive simulation study enables the development of a geologically consistent and efficient dynamic modeling approach. We briefly describe a methodology for generating effective properties at multiple geologic scales, incorporating the effect of channel architecture and reservoir connectivity into fast simulation models.

Geological modelling and history matching of multi-scale flow barriers in channelized reservoirs: methodology and application

ABSTRACT The key problem addressed in this paper arises in the situation where multi-scale shale drapes are present along channel, channel-belt and/or valley-bounding surfaces, but the channel location is uncertain or unknown. In order to reduce this uncertainty, the channel and drape locations should be modified in order to calibrate the flow response to the historic production data as well as any static data from wells. We propose a coupled geological modelling and history-matching method in which the reservoir architecture composed of channels is simulated with a pre-defined stacking pattern, then the shale drapes are simulated along the bounding surfaces using a multiple-point statistics technique and, finally, channel and scour-hole locations are gradually perturbed until the corresponding flow responses match the field production data. The perturbation during the history matching must be geologically consistent, i.e. the result must honour the observed individual channel geometries and the interpreted channel stacking patterns. A digital 3D model representing a real field in offshore West Africa was studied to demonstrate this modelling and history-matching approach in which the multi-scale shale drapes are simulated and perturbed while the reservoir geological concepts are preserved and the well data are honoured. The final history-matched geological models have better prediction power than geological models built with randomly selected input parameters.

Three-Dimensional Connectivity of Point-Bar Deposits

Abstract The geometry of heterogeneities within fluvial channel-belt deposits is predicted using an existing model of flow and sediment transport in river channel-meander bends. The thickest and coarsest-grained sediment accumulations are deposited near a channel-bend apex, and finer-grained sediments accumulate higher on the downstream end of a channel bar. Shale drapes deposited on individual beds during low flows are preserved mostly on downstream-dipping surfaces in finer-grained bar-top deposits. Extensive finer-grained deposits also accumulate in concave-bank areas in the lee of point bars when meanders migrate downstream. The coarsest deposits occur as elongate bodies parallel to the channel-belt axis when channel bends migrate mostly by downstream translation and are more circular when channel bends simply increase in sinuosity. The character of deposits preserved in concave-bank areas of the channel, the style of channel cutoff and filling during abandonment, and the amount of channel-belt aggradation during bar migration influence whether coarser-grained bodies of adjacent bar deposits are well connected. This 3D gridded model allows reservoir simulation studies that predict effects of types of deposit heterogeneity on patterns of subsurface flow through reservoirs and aquifers. Subsurface flow simulations suggest that channel belts with coarser-grained abandoned fills and significant vertical aggradation during bar migration constitute reservoirs with appreciably higher recovery factors than those with finer-grained channel abandoned fills and no vertical aggradation. Model results highlight the need to better understand connections between different types of facies associations in fluvial channel belts to improve predictions of fluvial-reservoir behavior.

Analysis and modeling of intermediate-scale reservoir heterogeneity based on a fluvial point-bar outcrop analog, Williams Fork Formation, Piceance Basin, Colorado

This study presents results of outcrop characterization and modeling of lithologic heterogeneity within a well-exposed point bar of the Williams Fork Formation in Coal Canyon, Piceance Basin, Colorado. This deposit represents an intermediate-scale depositional element that developed from a single meandering channel within a low net-to-gross ratio fluvial system. Williams Fork outcrops are analogs to petroleum reservoirs in the Piceance Basin and elsewhere. Analysis and modeling of the point bar involved outcrop measurements and ground-based high-resolution light detection and ranging data; thus, the stratigraphic frameworks accurately represent the channel-fill architecture. Two- and three-dimensional (2-D and 3-D) outcrop models and streamline simulations compare scenarios based on different lithologies, shale drapes, observed grain-size trends, petrophysical properties, and modeling methods. For 2-D models, continuous and discontinuous shale drapes on lateral-accretion surfaces result in a 79% increase and 24% decrease in breakthrough time (BTT), respectively, compared to models without shale drapes. The discontinuous shale drapes in the 2-D and 3-D models cause a 30% and 107% decrease, respectively, in sweep efficiency because they focus fluid flow downward to the base of the point bar. For similar reasons, 2-D models based on grain size exhibit 67–267% shorter BTT and 44–57% lower sweep efficiency compared to other model scenarios. Unlike the 2-D models, the continuous shale drapes in the 3-D models cause the fluid front to spread out and contact more of the reservoir, resulting in 42–53% longer BTT and 41–52% higher sweep efficiency compared to the other models. These results provide additional insight into the significance of intermediate-scale heterogeneity of fluvial reservoirs.

Deep-water plays of the Mauritanian continental margin

The coastal basin of Mauritania is emerging as a potential major petroleum province as a result of renewed exploration activity over the past five years. Two significant discoveries of oil and gas have been made at Chinguetti and Banda, proving that an effective petroleum system exists in this passive margin basin. The successful play type comprises Miocene turbidite channel reservoirs, sealed by fine-grained channel abandonment facies or a hemipelagic shale drape. The most prospective structures are associated with diapiric salt, although a variety of other structural styles, including compressional toe thrusts and rotated extensional fault blocks, are also present. The only source rocks proven to be effective in the immediate area occur in Cenomanian to Turonian deep-marine mudstones. However, regional evidence suggests that other intervals, including the Albian and the Paleocene, may also contain source facies. Future drilling campaigns by Woodside and other operators in the region will focus on realizing the value of existing discoveries through appraisal and tie-back exploration, while at the same time targeting new plays, particularly Late Cretaceous turbidites. Some of the major challenges to would-be petroleum explorers and producers in this basin centre around operating in a remote location almost totally lacking in infrastructure, and conducting activities in an environmentally responsible and sustainable manner.

THE CHINGUETTI DEEPWATER TURBIDITE FIELD, MAURITANIA: RESERVE ESTIMATION AND FIELD DEVELOPMENT USING UNCERTAINTY MANAGEMENT AND EXPERIMENTAL DESIGNS FOR MULTIPLE SCENARIO 3D MODELS

The Chinguetti Field was discovered in 2001 offshore Mauritania in 800 m of water. It comprises deepwater, mid-slope turbidite reservoirs, trapped in a dome over a salt diapir. The hydrocarbons are compartmentalised by concentric radial faults, in a low net:gross sequence, with oil mainly in channel sands. The large number of uncertain variables requires a structured approach and a rigorous assessment of the potential sub-surface scenarios. The field is of moderate size and risks in this deepwater environment need to be managed carefully.The main sub-surface uncertainties were identified by uncertainty framing and are briefly described in the paper. They include:structure;hydrocarbon contacts;fault seal;distribution of the channel systems;frequency and amalgamation of channel sands;shale drape;internal channel heterogeneity;effective pressure support;rock-fluid interaction;rock compaction;fluid composition/properties; androck properties.A statistical experimental design determined 27 scenarios should accurately model the probability distribution of reserves. A 3D model was made for each and run through the dynamic simulator to estimate economic ultimate recovery (EUR). Multivariate statistical analysis produced a response equation for EUR and the probability distribution. This is more rigorous than the standard method which produces mid, high and low case models, for which there is no adequate way to assign their probability of occurrence.