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This work was presented at the EAGE workshop in Grenoble. Its purpose was to illustrate a stratigraphic modelling approach on a single schematic 2D case and to discuss which sedimentary features are imaged on synthetic seismic sections at different frequencies. The Vercors plateau carbonate sequence, deposited during the Barremian to Early Aptian, was considered. Modelling hypotheses constrained mainly the depositional time length and the geometry of each sequence. In addition, it was assumed that most of the carbonates were produced in situ . The stratigraphic modelling approach and lessons from the simulation results are presented, followed by a discussion of how stratigraphic modelling can be a helpful tool to validate or question the geological model. In order to reproduce the sequence geometries, rates of carbonate production needed to be changed between regressive and transgressive periods. Simulated sea-level changes do not match the geological estimations from field interpretation but they are in agreement with the magnitude of sea-level curve variations, with the exception of the early Barremian sequences. Qualitative and quantitative results from the model simulations help to question or validate the geological model. Stratigraphic modelling provides some insight into the way the carbonate system may have worked. Secondly, for a smaller 2D geological model, several synthetic seismic sections were computed using wavelets of different dominant frequencies. The seismic sections are compared to underline what is imaged mainly at the different frequencies. The presence of two characteristic facies were also analysed. Results show the importance of some thin beds inside thick sequences and that certain sequence boundaries may not be visible at all.

Heavy oil, extra-heavy oil and tar sands account for half of the petroleum resources of the world. Due to their high viscosity their production is a major technical and economical challenge. The understanding of the origin and geological habitat of these unconventional oils is crucial in order to optimize exploration and production operations. The vast majority of these heavy oils originates from the biodegradation of conventional oils by bacterial activity. The limiting factors of the involved biological processes (temperature, nutrients, etc.) are controlled by the geological situation. In this respect, foreland basins which harbour a large part of the current deposits of heavy oils correspond to particularly favourable conditions in promoting the biodegradation of large charges of oil. They are characterized by long distance lateral oil migration draining substantial volume of the petroleum system. This migration is supported by an adequate drainage system which exhibits a large lateral continuity and consists of the first syntectonic fluvial and fluvial-deltaic sediments filling the foreland basins. As a result of this migration the oil reaches shallow situation in the forebulge where the temperature is compatible with bacterial activity. The reservoirs associated with the “forebulge” are often high porosity and high permeability sand bodies, initially hosting large volume of water and facilitating the circulation of meteoric water helping in the nutrient availability. For the sake of production, the heterogeneities associated with these fluvial and fluvial-deltaic sediments have to be carefully considered. The geological models developed for the architecture and for the stratigraphic evolution of fluvial channels and incised valleys provide useful guidelines in order to characterize the reservoirs for production purposes in such geological setting. The technical difficulties in recovering these highly viscous fluids require to integrate more detailed reservoir description than usually needed when producing conventional oil plays. The Cretaceous reservoirs of the Mannville Formation in Canada is presented to exemplify the types of heterogeneities encountered in fluvial reservoirs, their rational, their effect on the heavy oil recovery and the impact of the geological knowledge on the production strategy.

A numerical model has been developed to simulate sedimentary architecture resulting from turbidity currents over geological time. The model is based on the cellular automata paradigm. The automata exchange matter and energy and are built in order to reproduce the physical processes which govern turbidity current behavior. The simulated architecture is the result of a given set of geological events. For each of these events a steady state is computed that is assumed to be representative of the average effect of a turbidity current on the construction of the sedimentary architecture. Using model capacities, we reproduce the first sequence of the Lower Pab channel complex formation and a unit of lateral stacked channels of the Angolan deep offshore Girassol field. The model results show that the simulated sedimentary facies distribution is realistic and this may allow a better prediction of the deposits organization in turbiditic systems. Moreover, this model improves stratigraphic modelling resolution and can take over diffusive methods at reservoir scale. The advantages of this numerical approach are a better identification and understanding of deposits heterogeneities and may provide a better representation of the spatial organization, geometry and variability of the geological units that form reservoir architecture in deep-sea clastic systems.

The Pab Formation consists of deltaic and turbiditic sediments which were deposited during the Late Maastrichtian on the Indo-Pakistani passive margin. The margin geometry has been restored in the Pab Range from a regional transect 120 km long. Two superposed turbiditic systems onlap the slope carbonates and completely pinch-out southward. The lowest turbiditic system (Lower Pab) is a sand-rich basin floor fan, which consists of sand-rich channel complexes distally passing to lobes northward. This basin floor fan is overlain by a mud-rich slope fan formed during the subsequent sea-level rise, which drowned the shelf. The upper turbiditic system (Upper Pab) is a sand-rich slope fan, formed during the progradation of a deltaic system in the shelf setting. It consists of prograding tabular lobes passing upward to conglomeratic channels, and thins out northwards. The Lower Pab turbiditic system consists of three channel complexes (LP1, 2, 3) organised in a backstepping succession. Each channel complex has a multi-storey internal architecture, resulting from the amalgamation of several individual turbiditic channels. Five major facies associations have been determined in the LP3 channel complex. FA-1 corresponds to polygenic and monogenic debris-flows, FA-2 to high-density gravelly or sandy turbidites, FA-3 to by-pass deposits, FA-4 to thin-bedded turbidites (spill-over lobes and levees) and FA-5 to hemipelagites. The downstream evolution of the LP3 channel complex can be studied from canyon to mid-fan settings. Where it is confined in the canyon, the channel complex is 50 m thick and 1 km large, and shows a high sand/shale ratio. The development of overflow deposits is limited and occurs only at the top of the channel complex. At the canyon mouth, the channel complex is still deeply incised but overflow deposits start to expand laterally as a result of the decreased confinement. By-pass facies here are well-developed, and are related to hydraulic jump processes. In the mid-fan setting, the channel complex widens and the sand/shale ratio decreases. Erosion at the channel base is less developed, whereas internal and external levees are well-developed. Spill-over lobes form the last stage of the channel complex infill. The internal geometry of the channel complexes is a result of a complex interaction between lateral confinement, by-pass and lateral migration processes.

The aim of this paper is to review the geological factors which control the stratigraphic architecture of deep-sea fan deposits in passive margin settings. The recent discoveries of gaint hydrocarbon fields in the deep offshore of the Atlantic margins and of the Gulf of Mexico, and the related improvement of drilling and production technologies in very deep waters, have recently resulted in an intense activity in exploration of passive margins around the world. A vast amount of new data, and especially 3D seismic data, has been acquired, and its interpretation completely changes our views about the stratigraphic architecture of deep-sea fans. These new data sets also evidence our poor understanding of the sedimentary processes at the origin of the gravity flows, and highlight the diversity of the geological parameters controlling the evolution of these processes through time at the basin-scale.

The Cenomanian of the Arabian Peninsula comprises a carbonate platform setting with rudists, characterized by gradual lateral facies changes including the interfingering of carbonate reservoirs (Natih and Mishrif formations) and source rocks. In order to be more predictive with regard to the distribution and the geometrical aspects of the reservoirs and source rocks, a high resolution sequence stratigraphic study has been carried out in the Adam Foothills of Northern Oman. Based on detailed field sections a correlation scheme covering a transect of 100 kilometers (km) has been established. Three orders of stacked depositional sequences have been found based on the reoccurrence of facies. During long-term increase of accommodation the depositional environment was separated in basinal and platform facies. In contrast, during longer term sea level fall, i.e. long-term decrease of accommodation space, prograding shelfal units extended platform facies over a large part of the basin. The most heterogeneous facies associations are found in times of minimal accommodation space, when incisions and subaerial exposure produce lateral variable strata (e.g. top Natih E). The organic matter is found at the base of two of the three longer term (3rd order) depositional sequences. The organic carbon is contained in marl-limestone couplets (small-scale cyclicity) with a high abundance of oysters and monospecific brachiopod faunas (coquinas). Rudists are found in the progradational part of these sequences, and occur mostly as reworked rudstone layers in meter to decimeter scale, high frequency cycles. The detailed regional correlation depends on the identification of medium- to small-scale (4th to 5th order) depositional sequences which are bounded by regional shifts of the facies belts. The distinct hierarchical organization of the depositional sequences in the Cenomanian, and the relative stability at that time of the Arabian Peninsula, implies a strong correlation potential and thus a broad regional similarity of the architecture of the petroleum systems at that time.

International audience; The detailed facies analysis of the Zarzaitine outcrops (Illizi Basin in the In Amenas area of Algeria) allows the depositional environment of the Upper Triassic succession to be defined: braided rivers within an arid and humid alluvial plain, low sinuosity rivers within a humid alluvial plain, lake deposits and marginal sabkha. The description of the outcrops helps to define three types of genetic units from a proximal to a distal depositional environment: fluvial, fluvio-lacustrine and lacustrine. The spatial and temporal evolutions of the genetic unit were characterised by five specific stages from dry to wet climate conditions, inducing sediment supply and lake-level variations. During the first two stages (stage 1 and 2) under a dry climate, the lake level was low and sediments mostly by-passed and poorly preserved. During stages 3 and 4, an increase in humidity and rainfall induced a rise in the lake-level and the development of vegetation, as well as a decrease in the sediment supply, although the sediment preservation were then at its maximum. The last stage (stage 5) marked the beginning of a decrease in the humidity, the minimum of sediment supply and the maximum of the lake level. Therefore, the recognition and the description of genetic units within this fluvio-lacustrine environment help to demonstrate the interaction between climate, sediment supply and lake-level variation, at the scale of these units. Six stratigraphic cycles have been recognised in the vertically stacked genetic units and can be grouped in three megacycles (denoted as I­III). The first megacycle, attributed to Carnian to Norian, corresponds to the base of braided river systems with some ephemeral channels developed in an arid environment where some aeolian deposits were preserved. It evolved trough time to more humid conditions favouring the development of extensive floodplain, associated with hydromorphic soils, and perennial lake environments. During the Carnian times and Norian, the Zarzaitine area was not connected to the Berkine basin northward, a Hercynian unconformity palaeorelief forming a drainage divide. According to the directions of the palaeocurrents, the sediment provenances were mostly from the southwest and the north. The connection with the Berkine basin only occurred during the upper part of the megacycle II deposition, characterised by fluvio-lacustrine environments. The maximum flooding of the megacycle I, Norian in age, could be correlated with the early Norian maximum flooding observed on the Saharan platform. The late Norian­Rhaetian second megacycle was mostly a lacustrine environment associated with extensive floodplain, with the development of a hydromorphic palaeosol with root imprints attributed to a warm and wet climate. The maximum flooding episode of this second megacycle could be attributed to the major marine trangression recorded in Algeria, during the Rhaetian, and could be correlated with a relative sea-level rise. A dolomitic level, attributed to sabkha environments, marks the beginning of the retrogradational trend of the third cycle, attributed to the Rhaetian­Liassic. The palaeocurrent of the upper part of megacycle II and of the megacycle III were always oriented toward the northeast, attesting that the relief was located to the southwest.

The performance of heavy-oil production by Steam-Assisted Gravity Drainage process (SAGD) can be affected by near-well reservoir heterogeneities. However, as many factors interact during thermal production such as changes in oil viscosity, fluid saturations, pore pressure, stresses,... the interpretation of 4D seismic data in terms of steam chamber geometry is not direct nor unique.

During Palaeozoic times, the structuration of North Gondwana induced the formation of sub-basins separated by tectonic arches on the N orth African platforms. The slowly subsiding sub-basins were fed by periodically emerging and eroded arches (uplift vs eustatic sea-level drops) that control sediment distribution in space and time. The Devonian successions, located at the boundary between the Qarqaf arch and the subsiding Ghadamis basins in western Libya, represent a good record of this evolution and then an opportunity to discuss the relative influences of parameters that control the sequence architecture and reservoir distribution. The Devonian formations (Tadrart, Ouan Kasa, Awaynat Wanin, and Tahara Formations) in western Libya consist of more than 1000m of siliciclastic sediments. The succession is Pragian (Early Devonian) to Strunian (Late Devonian) in age and lies on Llandoverian (Early Silurian) shales along the Caledonian unconformity. These rocks are among the largest oil reservoirs in N orthern Africa. Most them are stratigraphic rather than structural traps and require detailed sedimentologic and stratigraphic works to improve the results of the exploration activities.This study based on outcrop and subsurface data respectively collected along the arch in Awaynat Wanin area and into the Ghadamis basin can provide some guidelines to fulfil this perspective.

The fine-scale architecture of turbiditic channels has been restored from the outcrops of the Pab sandstone in Pakistan. A 3D model was constructed from the outcrop interpretation and then informed in facies, petroacoustic and petrophysical properties. The model was used to calibrate process-based simulations reproducing the distribution of the heterogeneity at a fine-scale. Seismic simulations were then performed from the outcrop models and from the block issued of the process-based simulations. The effect of the small-scale heterogeneity on the seismic signature was then analysed and compared to real case-studies in subsurface.

International audience; In the intracontinental domain of the northwestern Saharan platform, the deformation of the Palaeozoic sedimentary cover is mainly attributed to a far-field effect of the Hercynian orogeny having occurred at the African-Laurusian plate boundary in the Late Carboniferous to Early Permian times. However, geological observations from different parts of Africa and Arabia provide evidence that several minor but widespread tectonic events occurred later, particularly during the Cretaceous. Contrary to elsewhere in the northwestern part of Africa, in the Reggane Basin, outcropping doleritic sills of Early Jurassic age are intruded in folded Palaeozoic sediments of Devonian to Carboniferous ages deposited before the Hercynian orogeny. In this favourable situation, a palaeomagnetic study of the Liassic dolerite is able to provide information on the tectonic history of the surrounding area independently from geological observations. The present study aims to quantify the relative proportion of tilting related to, respectively, the Hercynian and a post-intrusion phase, using a fold test based on the small circle analysis. This method proved to be very efficient to unravel these tectonic events. It shows that, in the studied area, the folds were initiated during the Hercynian phase, but mainly amplified during the post-intrusion phase which turned out to be the dominant one. In the Reggane Basin, the age of this second event is not geologically well constrained between probably Late Jurassic and Early Cretaceous. It could be the far-field effect of either the Cimmerian phase (∼140 Ma) or more likely the Austrian tectonic phase (Late Barremian, ∼125 Ma). The Late Barremian tectonic episode corresponds to a major event: the break-up of Western Gondwana, which led to the separation of Africa from South America and to the incipient fragmentation of the African plate into three major blocks. The conclusion drawn from the palaeomagnetic study in the Reggane Basin is consistent with the geological observations and representative of the intraplate Cretaceous deformations recorded in many other places in Africa. It emphasizes once again that stresses can be transferred far from the plate boundaries, into the continental plate interiors.

The EAGE Conference held in Algiers in April 2005 was the opportunity for 23 attendees to participate in a post-conference field-trip organized in the Tassili N’Ajjer outcrops in southern Algeria. The stratigraphic succession from the infra-Cambrian to the Middle Devonian is exposed in these exceptional outcrops, desert conditions favouring continuous exposure. The field trip started in the city of Djanet in the Infracambrian granites and shales and ended five days later in Illizi in the Lower Devonian Emsian sandstones (Figure 1). During the trip, these outcrops were described in terms of sedimentology, fracturation, and sequence stratigraphy. The outcrops of this area are of particular interest for petroleum geologists as the same sedimentary succession produces hydrocarbons in the nearby Illizi and Berkine basins and in the Hassi- Messaoud area. The Cambrian, Ordovician, and Devonian sandstones observed in the Tassili outcrops have an equivalent in the reservoir units in the subsurface. The Silurian hot shales are also the prolific source rock of the petroleum system in these basins. The succession presented in the outcrops can then be directly compared with the subsurface data of the Illizi and Berkine basins. The area was first surveyed by Killian (1922) who described the sedimentary succession of the region. Then, the lithostratigraphy and the Siluro-Devonian succession in the outcrops were established by Dubois et al. (1967). The reference study of the Lower Paleozoic outcrops in Algeria was published by Beuf et al. (1971). These authors proposed a lithostratigraphic nomenclature for the Lower Paleozoic and a sedimentological description of the formations. They also identified and interpreted the main unconformities in the Lower Paleozoic with a modern approach, discussing the relative role of tectonics and climate during sedimentation. A detailed mapping of the area was also performed by Sonatrach and Beicip under the supervision of the Ministere de l’Industrie of Algeria. However, since these pioneer studies, little has been published about the outcrop geology although hydrocarbon exploration and development has been very active in the nearby Illizi and Berkine basins. The objective of this paper is to propose a reference section for the Lower Paleozoic in the western Tassili with an updated sedimentological interpretation. An interpretation in terms of sequence stratigraphy will also be proposed. We then summarize the lithostratigraphy in use in the outcrops and propose a correspondence with the sub-surface.

B30 STRATIGRAPHIC ANALYSES OF THE LOWER DEVONIAN SEQUENCES REGGANE BASIN SOUTHESTERN ALGERIA 1 The present study provides an integrated stratigraphy of the Lower Devonian of the southeastern Reggane Basin Bled El Mass. It is important to establish a standard section allowing an interregional correlation as well as an interpretation of single environmental conditions their changes through time and their geographical extent. Numerous sections have been investigated in this area in addition to data from other profiles in the basin. Investigation of the sedimentary sequences is based on an analysis of events. Initially many events are diachronous whereas others are difficult

T046 SEDIMENTARY ARCHITECTURE OF THE SILURO-DEVONIAN SEQUENCES IN ILLIZI BASIN (ALGERIA) I. Introduction The aim of this paper is to present an example of a cratonic sedimentation during the Siluro- Devonian time in the Saharan craton. The particularity of sedimentation during this time is related to the morphology of Saharan basins climate and tectonic setting. This study consist of the caracterisation of the Siluro-Devonian sedimentation from field exposures in the “Tassilis des Ajjers” core and log data from drillholes in the Illizi basin II. Facies and depositional environments 1 MESSAOUDA HENNICHE 1 REMI ESCHARD 2 J.N PROUST 3 1

The integration of horizontal well data in static reservoir models results in better reservoir characterization in terms of structural geometry, facies and fracture distribution, and the quantification of heterogeneities. This improved characterization may have an impact on the dynamic reservoir model, and hence on production performance. An outcrop study was carried out at the reservoir scale, in order to address the principal issues to be resolved when integrating horizontal well data in a reservoir geological model, with emphasis on two key points: 1/ the loss of well information after discretization to a fine grid and 2/ the impact of the uncertainties associated with the well trajectory on the reservoir modeling. The chosen case study is the Upper Ismay interval of the Pennsylvanian Paradox Formation, whose depositional setting corresponded to a very shallow, mixed carbonate / siliciclastic platform. The geometry of the sedimentary bodies is roughly tabular at outcrop scale. Detailed sedimentological sections are described along the trajectory of several horizontal pseudo-wells logged on a continuous outcrop, with a horizontal length of around 200 meters. In this approach, the siliciclastic intervals, around 5 meters thick, are assumed to be reservoir targets. Shale breaks constitute internal heterogeneities and the carbonate layers are inter-reservoir barriers. A detailed geological reservoir model has been built from the outcrop database using a geostatistical approach. The type and volume of the data lost after discretization has been evaluated for different sizes of grid mesh. The influence of the uncertainties associated with the well location within the reservoir grid has been illustrated and quantified using several different trajectories described on the outcrop panel. For each pseudo-well included in the domain of uncertainty, geostatistical simulations have been performed and compared with a reference simulation, using the overall porous volume generated after simulation for quantification. This approach leads to key recommendations for the integration of horizontal well data in subsurface reservoir studies.

Geostatistics offers fast and flexible methods for reservoir studies and heterogeneity simulations. The starting point in every reservoir simulation process is the construction of the geological model. The type of geostatistical simulation used to reproduce the heterogeneity distribution depends on the sedimentary processes at the origin of the reservoir, and on the type of heterogeneity influencing the reservoir behaviour. This paper presents three outcrop examples that illustrate how to produce realistic geological simulations by optimising the simulation parameters, according to different geological settings. Both siliciclastic and carbonate reservoirs will be described.

History matching of geostatistical reservoir models requires efficient tools for coherently modifying model realizations. In recent years, the gradual deformation approach has been developed and successfully applied to several simple (synthetic or pseudo-real) cases. This paper presents the application of the gradual deformation method for history matching to a real oil field located offshore Brazil. The oil reservoir consists of turbiditic sandstones interbedded by shales and marls. The data set includes 47 wells with lithofacies description and 15 years production history. A fine scale geostatistical lithofacies model was built using the non-stationary truncated Gaussian approach. The model is conditioned to the lithofacies data at wells and takes into account the non-stationary distribution of the lithofacies. The sensitivity of the dynamic behavior with respect to the model realizations was studied. Preliminary results of using gradual deformation method for improving history matching are presented.

The Triassic reservoir is one of the most prolific plays in Algeria since the beginring of the exploration. One of the exploration risk is linked to the distribution and heterogeneity of the reservoir: Triassic series were mostly deposited in continental to lagoonal depositional environments, and reservoirs mostly correspond to channelised fluvial sandstones interfingering with floodplain and sabbkha sediments.

The aim of the present work is the geostatistical modeling of the distribution of heterogeneities in fluvial and eolian reservoirs, using both pixel-based and object-based approaches.

Reservoir modeling of the Chaunoy field was performed by combining a sedimentological study, a sequence stratigraphic analysis, geostatistical simulations, and the analysis of production data and fluid-flow simulations. The reservoir corresponds to the distal part of a Middle Triassic alluvial fan system in the Paris basin (France), and is extremely heterogeneous and layered. The reservoir mostly consists of small ribbon channel deposits interbedded with flood-plain and lacustrine mudstones. The channel amalgamation rate varied with cyclic lake-level variations, which directly controlled the reservoir geometry. Within a base-level cycle, during periods of low accommodation, channels were amalgamated, forming highly heterogeneous sand sheets. As the accommodation increased, channels became progressively isolated within flood-plain mudstones. Finally, a lacustrine transgression deposited lacustrine mudstones and induced thin but widespread vertical permeability barriers across the field. As accommodation started to decrease, considerable pedogenetic alteration occurred, as shown by dolocretes and groundwater dolomites. Five cycles that constituted the reservoir layering framework were identified. Geostatistical simulations of lithotype distribution within these units were computed using the truncated random Gaussian function method. Horizontal and vertical lithotype proportion curves and variograms were calculated from well data. Because of the wide well spacing, it was not possible to determine the range of horizontal experimental variograms. Three lithotype realizations were simulated within a high-resolution grid to compare short, medium, and long correlation lengths. After assigning petrophysical properties to the lithotypes and upscaling, fluid-flow simulations were performed for the three realizations. The three flow simulations were then compared to the 10-yr production history of the field. The simulations showed quite a good match regardless of the variogram range, except in the northern part of the field, indicating a problem in the reservoir layering in this area. This relative insensibility of the flow simulation to the correlation length probably is due to the high net pay within the amalgamated channel reservoir units and to the high number of conditioning wells; however, the flow simulation performed with the longest correlation length showed the best fit with the production history.

P. Johann,^ Petrobras S.A.; F. Fournier, SPE, Institut Francais du Petrole; O. Souza Jr., Petrobras S.A.; R. Eschard, Institut Francais du Petrole; H. Beucher, Centre de Geostatistique de l'Ecole Nationale Superieure des Mines de Paris. Abstract A new methodology for 3-D stochastic reservoir modeling constrained by well and seismic data is applied to a pilot area, the Namorado turbidite giant oil field in the Campos basin. The stochastic modeling is based on a truncated Gaussian approach, with a non stationary algorithm using a 3-D matrix of lithotype proportions. The proportion matrix can he constrained by qualitative or quantitative seismic derived information. Qualitative information corresponds to vertical proportion curves, predicted at the trace locations, from seismic facies analysis. Quantitative information are estimates of lithotype thicknesses, over all the reservoir section, derived from calibration of seismic attributes. Whatever type of seismic constraints -qualitative or quantitative- their incorporation in the reservoir modeling led to a major improvement of reservoir heterogeneity representation, in the case of the Namorado field. The methodology is thus promising for other fields, particularly in turbidite environment. Introduction Reservoir stochastic modeling provides a good frame for integrating data of different sources and qualities. It leads to a more realistic 3-D reservoir image associated with risk assessment through an improved uncertainty representation. Well logs and core data provide detailed information about vertical variations of many reservoirs properties but they are restricted to regions adjacent to the borehole. Conversely, 3-D seismic data offer a dense coverage of the interwell areas and therefore should play a key role in describing reservoir heterogeneities. However, the integration of seismic data in reservoir stochastic models is still a challenge. Most of the time, the reservoir is described as a high resolution 3-D model of lithotypes and/or petrophysical properties, in which seismic information has to be incorporated. The difficulties for this incorporation are due to very different measurement scale for seismic and well information, and to often complex and non unique relationship between the useful reservoir properties and the acoustic or elastic parameters. Therefore, a direct incorporation of seismic information (amplitudes, acoustic impedances…) in the stochastic modeling is possible only in a limited number of cases, corresponding to simple (homogeneous) reservoirs. Unfortunately, it is not the frame of nearly homogeneous reservoirs for which seismic data is so crucial for bringing extra information between wells, since very small geological variations are expected in this case. In this paper, a conservative approach for integration of seismic in 3-D stochastic modeling is proposed. The key point is to break the problem in two steps. Firstly, the seismic information is turned into average geological information, directly related to the modeling process. Secondly, this information is accounted as global and soft constraints in the modeling. This approach allows to overcome both difficulties of scale and indirect relationship between seismic data and reservoir properties to simulate. Two possibilities are proposed for extracting the soft geological information contained in the seismic data. The first one, based on seismic facies analysis, provides a qualitative interpretation of the reservoir interval in terms of geological behavior. The second one uses statistical calibration techniques to derive estimates on average reservoir properties (quantitative information). Both kind of information -qualitative and quantitative- are integrated in the 3-D modeling of lithotypes using a non stationary truncated Gaussian approach (Figure 1). P. 51

In intensive exploration and reservoir appraisal, geostatistical simulations are often computed to optimize the reservoir management at an early stage of the field development. But at this stage, the uncertainty associated to the simulation remains high because of the lack of data (few wells, poor seismic coverage).

Abstract An integrated study combining sedimentological and sequence stratigraphy analysis, geostatistical simulations and validation by production history simulation has been performed in the Chaunoy field reservoir. The reservoir is a part of a distal alluvial fan system, in the Keuper series of the Paris Basin (France). RFT surveys suggest a layered behavior. Nevertheless, the low extension of reservoir bodies (small ribbon channels interbedded with flood-plain and lacustrine mudstones) made it difficult to set ut a satisfactory correlation scheme in the past studies, resulting in difficulties in matching the production history. Core and log analysis yielded the conceptual geological model. Geostatistical analysis enabled to its validation and quantification. Inside each genetic unit, repartition of lithotypes and of petrophysical properties were modelled by geostatistical simulations. As the horizontal variogram ranges proved to be below the average well spacing, three high resolution models were built, with different horizontal variogram ranges, all smaller than well-spacing (1/8, 1/2 or 1 times the well spacing). After scaling-up of the resulting petrophysical models, simulations of the ten-year production history were performed - in each model. By comparing the simulated production data with the field production history, the characterization study was validated. A satisfactory match was obtained on the main zone of the reservoir, validating the correlation scheme and explaining the observed layered behavior. Introduction In the recent years, the oil industry has focused on reservoir characterization as a key to better reservoir management. Progresses has come from the geology (sequence stratigraphy and numerical simulation of geology) and from the development of 3-D seismic. Geological simulations are mainly obtained through geostatistical techniques, though deterministic methods also exist. In the scope of reservoir engineering, up-scaling techniques and use of probabilistic methods have accompanied the progress of geological descriptions. These advances, coupled with the availability of powerful and relatively inexpensive computer stations, and of data-base and visualization software, drive the industry towards a better integration. Refs. 1 to 4 present examples of recent studies incorporating the new geological techniques which proved to be efficient in going directly to history-matched reservoir models. Emphasis is put on the role of a good geological characterization to get a predictive reservoir model. The present field case goes from the geological analysis of cores and logs through the building of high-resolution geological models to the validation of reservoir models, within an integrated framework. The geological modelling of complex reservoirs requires a combination of conceptual stratigraphic models and probabilistic simulations. The first approach enables one to predict the reservoir geometry and extension within a deterministic framework. High resolution sequence stratigraphy has considerably improved our understanding of the genetic unit architecture in function of accommodation variations. Its application at the reservoir scale provides the correlation scheme of the reservoir. Furthermore, these conceptual models are able to predict the reservoir extension and architecture up to a certain level: estimation of the channel amalgamation, or of shore-face sequence extensions are a few examples amongst many others. Even sand/shale ratios, and then gross reservoir quality can be predicted with such an approach. However, in many cases, if such conceptual models are essential at reservoir scale, their accuracy often remains insufficient to predict realistically the distribution of internal heterogeneities within reservoir units. Furthermore, fluid- flow modelling requires a representation in terms of petrophysical properties. For that purpose, the stochastic approach is more and more applied in subsurface to simulate the distribution of either small-scale sedimentary bodies or the internal reservoir heterogeneity. Another advantage of stochastic approach is to provide equiprobable realizations of the heterogeneity distribution. P. 23

As part of a project designed to use stratigraphically identified fluid-flow units as input for reservoir simulation, we have used surface correlations to aid subsurface correlations of strata within the Mesa Verde Group, San Juan basin, Colorado. Surface correlations show changes in symmetry of stratigraphic cycles and changes in facies types and associations within different parts of stratigraphic cycles. A knowledge of these changes in facies within a stratigraphic context is an invaluable aid in high-resolution subsurface correlation and in mapping fluid-flow compartments. In miles-long continuous exposures in Mancos Canyon, we have identified very low-angle (0.12{degrees}) clinoforms in shoreface strata of the Point Lookout Formations. Strata within groups of clinoforms of base-level fall hemicycles show shallowing-up vertical profiles in shelf through upper shoreface facies. The shallowest facies of the most seaward (youngest) shoreface clinoform package is overlain either by a thin deepening-up facies succession or by a transgressive surface of starvation followed by another shallowing-upward facies succession. Farther landward base-level hemicycles are recognized by alternations in types of channelbelt sandstones and lake and floodplain mudstones. Base-level rise strata generally show increasing aggradation and sediment preservation in a landward direction for a few miles. The most continuous, and often the thickest,more » mud-rich strata occur at the base-level rise to fall turn-around positions in all environments. These continuous, low-permeability strata follow the topography of clinoforms and divide the reservoir quality sandstones of the shoreface, tidally influenced estuary and bay, and channelbelts into reservoir compartments. Sandstones of the compartments average 10-15 m thick, dip at 0.12{degrees} through the shoreface, extend an average of 13 km in the dip direction, and at least 10 km in strike directions.« less

Over the past decade, theory and experiments have shown that changes of reflection amplitude with offset (AVO) in multi-offset seismic records are strongly affected by relative changes of Poisson's ratio. AVO analysis opens the possibility to distinguish ‘bright spots’ due to gas accumulation from those caused by other changes in lithology AVO analysis is generally carried out with ray tracing and the Zoeppritz equations as tools for forward modeling. Some inversion procedures have been developed to infer changes in the contrast of the elastic parameters. However, it was recognized that the quality of the available modeling and inversion techniques was insufficient. The alternative approach we propose for the modeling is (i) an extension of the reflectivity method to smoothly varying media, and (ii) a cost-efficient linearized finite-difference technique.In our study we have minimized structural difficulties in order to concentrate on a 2D target zone in a quasi-layered background media. Then small changes in elastic parameter contrasts can be estimated by inversion using a linear least-squares approach: the waveform match between the synthetic and the seismic multi-offset gathers is obtained by perturbing the model parameters in the target zone. We have also evaluated the impact of the use of a priori information. Finally a 2D seismic non-linear modeling has been carried out to understand what reservoir-scale information is contained in the seismic reflection data. Participants in this project were AGIP (Italian oil company), the Politecnico di Milano(POLIMI) and the Institut Francais du Petrole (IFP). Each partner of this project has contributed specialskills and experience. The task of AGIP, the industrial partner, was to analyse a real data ase with the maximum depth possible, and to extract all information on the elastic parameters.The role of the academic partner, Politecnico di Milano, was to improve elastic reflectivity modeling and to evaluate the uncertainties of both amplitude-versus-offset (AVO) studies and of linearized elastic inversion that are caused by uncertainties in the model of the overburden and by noise in the data. An effort was also made to implement the inversion technique in the (ω-k domain. The role of IFP was to develop both linearized elastic modeling and inversion techniques using finite differences, and to evaluate the inversion technique on a large-scale synthetic data set. In addition, a multidisciplinary team of IFP has carried out a numerical simulation of synthetic data bas d on controlled earth parameters followed by processing and interpretation. Part I deals with the impact of a priori information on seismic inversion.It was decided to improve the most accurate modeling technique, i.e., the well known reflectivity method, so that it better represents shorter offsets; subsequently it was extended to media that vary continuously with depth, and to media that vary smoothly in lateral direction. This was achieved by the hybridization of ray tracing and reflectivity methods. A powerful (and essentially exact) 3D modeling technique resulted, albeit limited to quasi ID media. The AGIP group was able to analyse a real data case that was suitable for this kind of modeling. This group has carried out a careful and systematic AVO analysis and a comparison between the elastically modeled data and the real data. The processing and interpretation steps are described below. Another important step was to determine error bars in linearized inversion. For this, it was useful to move the problem from the spatial domain to the frequency-wave number domain. This move opened the possibility to bette understand the ‘conditioning‘. The inversion in the ω-k domain (with some preliminary results) is presented below. It was necessary to understand not only linearized inversion, but the limits of AVO in general. To this end a complete study of the interaction between AVO and velocity errors was carried out. This thorough understanding is particularly important if the velocity is not as perfectly known as in the real data case we analysed. Part II describes a 2D linearized elastic inversion technique and its evaluation on synthetic data.A 2D linearized elastic modeling procedure based on the computation of the Jacobian matrix using finite differences was proposed, analysed and implemented. Its accuracy was tested for models containing a few scattering points. Besides linearized modeling, a linearized inversion technique using a least-squares formulation was implemented to find the elastic perturbations in the 2D target zone. The inversion was tested on seismic data generated from scattering points. Next a large-scale synthetic data set generated for a gas-bearing sand model by a full-wave elastic finite-difference code was inverted. We show that, by using a plane stratified reference medium and limited windows for parameters data centered on the reflected P-P waves, one can determine the band-limited perturbations of the P-impedance and - to a lesser degree - the band-limited perturbations of the S-impedance at reasonable effort. In addition we show that the inversion results are closer to the actual perturbations than the results obtained with more conventional seismic processing procedures. Part III describes a numerical simulation of synthetic data for the Mesaverde outcrop.The objective was to understand what geological information is embodied in the seismic data that can be used to delineate and characterize reservoirs. Both geological and elastic models were constructed from the Mesaverde outcrop study and from industrial logs of equivalent formations. Then (marine) synthetic data were generated using a full-wave 2D elastic propagation code. Conventional seismic data processing was applied to obtain a stacked section. This section was calibrated using impedance logs at theoretical well locations (this process corresponds to wavelet-extraction processing). Finally complementary direct and inverse stratigraphie impedance modeling techniques were applied to build the most likely impedance section and to give a geological significance to the impedance variations.

Abstract Decision of implementing two polymer-augmented waterflooding pilots in Daqing was taken in 1987 considering favorable laboratory results and preliminary reservoir studies. Since that date, the preliminary reservoir studies. Since that date, the drilling of 8 injectors and 18 producers representing 4 inverted five-spot for each pilot has been achieved. The formation is composed of different superimposed reservoirs. Each reservoir itself is constituted of numerous embedded sand and shale layers, characteristic of fluvio-deltaic deposits. Pilot PO is devoted to one reservoir while polymer Pilot PO is devoted to one reservoir while polymer injection in pilot PT will be simultaneously performed in two reservoirs which has been found to performed in two reservoirs which has been found to be more representative of injection conditions in Daqing. Oil viscosity is 9.5 cp. Drilling was accompanied by an intensive program of data collection such as electric logging, coring, DST and interference tests. The paper presents how these data have been interpreted in terms of geological deposit to give the best possible vertical and areal description of each reservoir as well as their integration in the 3D chemical model SARIP designed by IFP. Polymer injected is HPAM at a concentration of 915 ppm. The paper discusses the different results of simulation, focusing on fluid and polymer production profiles and areal distribution in each production profiles and areal distribution in each reservoir. The predicted range of incremental oil recovery inherent in polymer is dependent on the severity of the reservoir heterogeneity and varies from 7.5% in stratified areas to 12% when the formation is more homogeneous. This indicates a better polymer efficiency to reduce the detrimental water-oil mobility ratio than to correct the rock permeability profile. profile. The paper ends by a presentation of the first field production results of the pilots that were put in production results of the pilots that were put in stream in 1989. Introduction Reservoir description Discovered in 1959, the field of Daqing is one of the largest oil reservoirs of the People's Republic of China. The field is located in the central depression part of the continental sedimentary basin of part of the continental sedimentary basin of Songliao, 1 000 km north of Beijing, in place of a pre-existing large continental lake where sediments pre-existing large continental lake where sediments resulting from intense orogeny had been transported during the Mesozoic and Cenozoic periods. The total thickness of sediments in the basin is 6 000 to 7 000 m. The structure is an elongated N-NE/S-SW anticline, 145 km long and 10 km wide. Vertically the reservoir consists of three potentially commercial formations of early Cretaceous age namely: Goataizi, Putuahoa and Saertu. Only Putuahoa and Saertu formations have been developed Putuahoa and Saertu formations have been developed so far. P. 331

Abstract A method for evaluating the production scenarios in the delineation phase of an oil field is described, and illustrated with a synthetic example build from a Mesa Verde (Colorado) area outcrop. At delineation time, only a few wells and some geophysical surveys are available for reservoir characterization. The geologist analyses these data, and determines some major characteristics of the deposition system as its type, its direction, etc. This interpretation is then quantified so as to be used as the input of a geostatistical simulation model, in terms of lithofacies proportion curves, and variogram function parameters. This quantification is not unique, and the geologist provides ranges for each parameter. The geostatistical simulator gives several images, with different parameters varying in the selected ranges. A first investigation among these images is performed by looking at the volume of reservoir connected to the producing or injecting wells, for various wells spacing. Then, these images are translated into petrophysical description, allowing to perform oil petrophysical description, allowing to perform oil recovery calculations, for the selected images. Finally, an estimation of the oil production for different development scenarios, taking into account uncertainties is performed. This methodology is possible thanks to a geostatistical simulation model enabling integration of geology and reservoir engineering. The geostatistical simulation model is a tool for translating geological knowledge into parameters manageable for reservoir engineers. The proposed methodology allows to make better decisions in the delineation phase, as impact of uncertainty can be more easily computed. The availability of an integrated model, avoiding painful data handling (petrophysical data attribution, upscaling), is an important point. Introduction 1-1 THE PROBLEM Once an exploration well has shown the presence of hydrocarbon bearing formations, a presence of hydrocarbon bearing formations, a program of delineation well drilling begins. That program of delineation well drilling begins. That program aims at determining the major features of program aims at determining the major features of the discovered field, in order to be able to appraise its economical value. These features are:–The type of trap (structural, stratigraphical, by fault, etc).–The geometry of the reservoir (shape, interconnectedness, volume of porous and permeable reservoir).–The petrophysical characteristics of the reservoir.–The fissuration, if any. P. 209

The use of new coneepts in sedimentological interpretation (stratigraphic sequences, carefully done deseription of the cores...) combined with new tools in geostatistics (variograms, proportion curves...) allows to characterize the size and the frequency of sedimentary bodies and of their internal heterogeneities. The geological interpretations and constraints appear to be crucial prerequisites for the consistency of the method.

In the Middle Jurassic series of the Cleveland basin (England), an accurate three-dimensional reconstruction of depositional sequences from outcrops, cores, and wireline logs show that minor sea level variations control the evolution of a deltaic system. Because of low subsidence and sediment supply rates, rapid sea level rises induce several landward shifts of the shoreline, whereas minor sea level drops produce the incision of small paleovalleys. The deltaic series, 200 m thick at the basin depocenter, are subdivided into five depositional sequences. During the first two sequences, the sediment supply rate exceeds the relative sea level rate and the delta progrades. The delta aggrades during the third depositional sequence and retrogrades in the fourth depositional sequence when the relative sea level rise rate balances then exceeds the sediment supply rate. Finally, a relative sea level drop induces the incision of a paleovalley progressively infilled during the following sea level rise. Several orders of bathymetric cycles are deduced from detailed correlations of the unconformities and from the comparison of the vertical facies succession between low and high subsiding areas. The general evolution of the delta is related to a 5-m.y. bathymetric cycle due to a eustatic sea level rise and fall.more » Pne to 3-m.y. bathymetric cycles control the main aggradation patterns of the delta. These patterns are related to third-order eustatic cycles or to local tectonic events. Less than 0.5 m.y. bathymetric cycles are registrated by parasequences or minor depositional sequences which are correlated all over the basin. The controlling parameters of the sequences are discussed. Minor bathymetric cycles (0.2 m.y.) reflect small-scale sea level oscillations or autocyclic evolution of the sedimentary bodies. The authors focus on the reservoir geometry within each bathymetric cycle.« less

The aim of this paper is to test a new approach combining ¢eld studies and sequence stratigraphic analysis to gain insights into the in£uence of local deformation on the sequence stratigraphic architecture of syndeformational deposits.To assess the in£uence of fold growth on coeval deltaic sedimentation, we investigated the development of the Pico del Aguila anticline, a kilometre-scale compressive fold in the Jaca basin, located on the south-western border of the Pyrenean foreland basin. We analyse six stratigraphic sections located along the structure, identifying the facies associations and palaeoenvironments.This leads us to propose a new sequence stratigraphic framework, taking into account three orders of depositional cycle (genetic units, minor cycles and major cycles) and their stacking pattern.We quantify the rates of accommodation variation, sediment accumulation and relative uplift of the anticline, showing that minor cycles are driven by accommodation variations of regional scale rather than sediment supply variations.We also demonstrate that the uplift rate of the anticline axis is continuously decreasing through time.The growth of the anticline exerts four diierent types of control: (i) on the distribution of sedimentary thicknesses, (ii) on the depositional pro¢le (shallower facies are preserved on the hinge of the anticline), (iii) on the thickness ratio between the progradational and retrogradational sub- cycles (P/R ratio) of the depositional sequences (most of the thickness diierences arise during the prograding trend) and (iv) locally, on the timing of the transition from progradational to retrogradational trend between the hinge and the synclines.The growth of the anticline consistently distorts the geometry of the three scales of depositional cycles, to an extent depending upon the diierence in subsidence rate between the hinge and the synclines (i.e. the uplift rate).The distortions of the ratio between the thicknesses of progradational and retrogradational sub- cycles and the variation in the timing of the trend inversion can be explained by a simple superimposition of continuous uplift of the anticline (local deformation) and regional variations of relative sea level (eustasy and/or foreland basin subsidence).

In the western Mediterranean basin lies a rift system about 250 km long and 50 km wide and its infilling outcrop (central Sardinia). Seismic reflection surveys show its offshore extension. Block tilting started during the late Oligocene and lasted during Aquitanian-early Burdigalian time. Two main fault trends, with synthetic and antithetic throws, define the more-or-less collapsed blocks. This morphology guided the transit and trapping of sediments. The sedimentation started in a continental environment then, since the Chattian, in marine conditions. In the central part, the series can reach a thickness of 2,000 m. The basement composition and the volcanics products related to the main fault motion controlled the nature of the synrift deposits. According to their location in the rift context, the tilted blocks trap either continental deposits or marine siliciclastic or carbonate deposits. In the deeper part of the graben, sands were redeposited by gravity flows into the basinal marls. The younger prerift deposits are from Eocene to early Oligocene age and locally comprise thick coal layers. Postrift deposits, mainly marls, sealed the blocks and synrift sedimentary bodies. In middle and late Miocene time some faults were reactivated during compressional events. Then, a quaternary extensional phase created the Campidanomore » graben, filled with about 1,000 m of sediments superimposed on the Oligocene-Miocene rift.« less