Sensitivity of the impact of geological uncertainty on production from faulted and unfaulted shallow-marine oil reservoirs: objectives and methods (original) (raw)
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Reservoir characterization and modeling of lateral heterogeneity using multivariate analysis
Energy, Exploration & Exploitation, 2014
Reservoir characterization deals with the description of the reservoir in detail for rock and fluid properties within a zone of interest. The scope of this study is to model lateral continuity of lithofacies and characterize reservoir rock properties using geostatistical approach on multiple data sets obtained from a structural depression in the bight of Bohai basin, China. Analytical methods used include basic log analysis with normalization. Alternating deflections observed on spontaneous potential (SP) log and resistivity log served as the basis for delineating reservoir sand units and later tied to seismic data. Computation of variogram was done on the generated petrophysical logs prior to adopting suitable simulation algorithms for the data types. Sequential indicator simulation (SIS) was used for facies modeling while sequential gaussian simulation (SGS) was adopted for the continuous logs. The geomodel built with faults and stratigraphical attitude gave unique result for the depositional environment studied. Heterogeneity was observed within the zone both in the faulted and unfaulted area. Reservoir rock properties observed follows the interfingering pattern of rock units and is either truncated by structural discontinuities or naturally pinches out. Petrophysical property models successfully accounted for lithofacies distribution. Porosity volume computed against SP volume resulted in Net to gross volume while Impedance volume results gave credibility to the earlier defined locations of lithofacies (sand and shale) characterized by porosity and permeability. Use of multiple variables in modeling lithofacies and characterizing reservoir units for rock properties has been revisited with success using hydrocarbon exploration data. An integrated approach to subsurface lithological units and hydrocarbon potential assessment has been given priority using stochastic means of laterally populating rock column with properties. This method finds application in production assessment and predicting rock properties with scale disparity during hydrocarbon exploration.
Petroleum …, 2008
Several key parameters that describe a prograding shallow-marine reservoir are investigated for their relative importance on hydrocarbon production variability. Sedimentological parameters are aggradation angle, progradation direction relative to the waterflood, continuity of cemented surfaces and shoreline curvature. Structural parameters are the fault pattern, the density (throw) of the faults and the fault-rock permeability. The last component investigated is the effect of well placements. Having three distinct levels for all sedimentological and structural parameters in addition to a non-faulted case gives a dataset of 2268 reservoir models. Four different sets of well locations produce 9072 production datasets. The variability of the production data is decomposed into its explanatory factors in order to see the relative importance of the chosen parameters. The production data include the total production, the discounted production and the recovery factor. The sedimentological parameters dominate both the production and the discounted production variability, especially the aggradation angle and progradation direction, whereas the fault pattern is equally significant for the recovery factor. Continuity of sedimentological barriers were found to contribute less than expected to the production variability for these reservoir models, and the well placements also showed a low effect.
SPE 164830 How to integrate basin-scale information into reservoir models
Objectives and scope of the Study In this paper a new approach is presented to consistently integrate basin-scale information into reservoir models. The impact of the quantitative integration of boundary conditions derived from basin-scale modeling on the facies distribution at the reservoir scale is evaluated. To this purpose, a new workflow was defined based on a geostatistical approach. The aim was that of integrating the typical dataset for reservoir geological modeling, comprising well and seismic data, with a potentially new kind of data obtained from 3-D process-based stratigraphic modeling and related to the distribution of the hydrocarbon bearing volumes. Quantitative coherence between the small scale reservoir volume and the large-scale geological setting defined by the basin model was imposed. Synthetic case studies were set up to verify the effectiveness of the method. Applications The entire process was applied to a fluvio-deltaic environment to integrate the basin-derived information, such as (1) the overall reservoir/non reservoir volumes, (2) the 3D distribution of channelized volumes and (3) related flow directions, to the reservoir model. Eventually, the uncertainty reduction in the description of the final facies distribution at the reservoir scale was evaluated. Results, Observations and Conclusions The developed approach proved very efficient to estimate the lithological fraction of the hydrocarbon bearing rocks (i.e. sands in a shaley/clayey environment). The lithological fraction is of crucial importance during the appraisal phase of a reservoir when relevant decisions have to be taken but few wells are drilled and, as a consequence, a limited amount of data is available to perform a reliable volumetric estimate. Furthermore, the prediction of the 3D facies architecture (such as the channel pattern in a fluvial depositional environment) can effectively assist in the well planning strategy. Besides, the overall uncertainty affecting a reservoir model can be assessed; this uncertainty is both a function of the initial environmental parameters for basin modeling and of the adopted methodological approach for basin-to-reservoir data integration. Therefore, an accurate inference of the basin parameters is needed to achieve a reliable prediction of both the channel location and the sand/shales volumes fractions. Significance of subject matter Reservoir modeling can significantly benefit from the integration of quantitative basin-scale information. In particular, the numerical modeling of the stratigraphic sequence can be used to steer the reconstruction of the reservoir internal geometry and to reduce the uncertainty in the distribution of the hydrocarbon-bearing lithologies. Furthermore, this approach provides a rigorous assessment of the information content of all the available data and thus it might be very useful to guide further data acquisition campaigns.
Uncertainty Analysis of a Fractured Reservoir’s Performance: A Case Study
Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles, 2012
Analyse d'incertitudes des performances d'un réservoir fracturé : étude de cas -Ces dernières années, l'industrie du pétrole a accordé une grande importance à la gestion et à l'analyse d'incertitudes des réservoirs. Le développement d'une méthode permettant de modéliser et de quantifier les incertitudes au cours des études de simulation de réservoir d'une façon efficace et pratique est clairement souhaitable. Des approches différentes telles que la méthodologie des surfaces de réponse (RSM ; Response Surface Methodology) et la simulation de Monte-Carlo ont été utilisées pour évaluer les incertitudes. Au sein de cet article, la méthode de surface de réponse est utilisée pour appréhender les paramètres les plus influents sur les changements en termes de chute de pression et de facteur de récupération, en ce qui concerne leurs niveaux pratiques d'incertitudes au cours du développement d'un modèle de réservoir fracturé. La présente approche est utilisée pour amplifier les paramètres significatifs et développer une équation substitutive compatible et plus réaliste en vue de la prévision de la récupération d'huile à partir d'un réservoir fracturé faiblement perméable typique. Le modèle substitutif permet à l'analyse de Monte-Carlo de déterminer les sensibilités et la quantification de l'incidence de l'incertitude sur les prévisions de production. Les résultats indiquent que la récupération d'huile est plus sensible à la pression de l'aquifère, à la perméabilité de fracture et à la hauteur de bloc. De plus, toutefois, l'interaction entre d'autres paramètres tels que la taille de matrice, la perméabilité de fracture et le volume d'aquifère a montré un certain degré d'importance au cours de cette analyse. L'analyse de Monte-Carlo prévoit un domaine de grande ampleur de récupération d'huile pour l'exploitation de ce champ.
A study of the structural controls on oil recovery from shallow-marine reservoirs
Petroleum …, 2008
The differences in oil production are examined for a simulated waterflood of faulted and unfaulted versions of synthetic shallow-marine reservoir models with a range of structural and sedimentological characteristics. Fault juxtaposition can reduce the economic value of the reservoirs by up to 30%, with the greatest losses observed in models with lower sedimentological aggradation angles and faults striking parallel to waterflood direction. Fault rock has a greater effect than fault juxtaposition on lowering the economic value of the reservoir models in the compartmentalized cases only -and only when the fault rock permeability model is based on the least permeable published laboratory data. Moderately sealing faults can increase the economic value of reservoirs except when the main flow direction is parallel to the faults. These results arise from the dependence of economic value on both sweep efficiency and production rate. Simple predictors of fault juxtaposition and fault-rock heterogeneity have been established and combined with twodimensional considerations from streamline theory in an attempt to capture quantitatively the change in economic reservoir value arising from faults. Despite limitations associated with the three-dimensional role of juxtaposition, the results are encouraging and represent a step towards establishing a rapid transportable predictor of the effects of faults on production.
Integration of production data into reservoir models
Petroleum Geoscience, 2001
The problem of mapping reservoir properties, such as porosity and permeability, and of assessing the uncertainty in the mapping has been largely approached probabilistically, i.e. uncertainty is estimated based on the properties of an ensemble of random realizations of the reservoir properties all of which satisfy constraints provided by data and prior geological knowledge. When the constraints include observations of production characteristics, the problem of generating a representative ensemble of realizations can be quite difficult partly because the connection between a measurement of water-cut or GOR at a well and the permeability at some other location is by no means obvious. In this paper, the progress towards incorporation of production data and remaining challenges are reviewed.
Oil & Gas Science and Technology-revue De L Institut Francais Du Petrole - OIL GAS SCI TECHNOL, 2001
-Hétérogénéités du réservoir fluvial et fracturé du champ pétrolifère de Buchan (partie centrale de la mer du Nord)-Le réservoir pétrolier de Buchan, dans la mer du Nord, présente dans sa partie centrale une complexité du point de vue structural au niveau du Dévonien-Carbonifère. Ce réservoir se caractérise par une succession de séquences décroissantes, à dominance gréseuse de type chenaux en tresse. L'analyse hiérarchique de la qualité du réservoir, à l'échelle microscopique (lames minces), à l'échelle moyenne ou méso (lithofaciès et séquences de faciès) et à grande échelle ou méga (plus d'une séquence), montre que le réservoir peut être divisé en six grandes unités. Cette subdivision a été réalisée en se basant sur les propriétés sédimentologiques, sur les valeurs de la perméabilité et de la porosité, ainsi que sur les réponses des logs électriques. Les propriétés de ces unités aux échelles microscopique et moyenne, particulièrement la présence de fractures et les variations du coefficient de corrélation entre la porosité et le logarithme de la perméabilité, apportent une bonne contribution pour définir les zones efficaces et non efficaces du réservoir se trouvant dans ces unités. La zone la plus efficace, située entre 2738 et 2788 m, est caractérisée par une prédominance de roches de type subarkose à quartzarénite fracturées. Cette zone diffère des autres zones gréseuses du réservoir par une préservation de la porosité intergranulaire primaire ainsi que par une porosité secondaire issue du système de fracturation présent. Les valeurs de la porosité et de la perméabilité peuvent atteindre jusqu'à 30,2 % pour la porosité et 1475 mD pour la perméabilité. Une zone identique a été découverte, s'étendant presque tout le long du champ pétrolifère, et elle définit avec précision la partie la plus productive d'un point de vue qualité du réservoir. Mots-clés : champ pétrolifère de Buchan, hétérogénéités du réservoir, évaluation de la zone productive.