Distribution Of Reservoir Properties Research Articles

Estimating Vsand and reservoir properties from seismic attributes and acoustic impedance inversion: A case study from the Mansuri oilfield, SW Iran

This study integrates 3D seismic attributes and well log data to determine Vsand and reservoir property distribution of the Oligo-Miocene Asmari Formation in the western Dezfol Embayment, SW Iran. The rocks consist of complex geology with siliciclastic and carbonate lithology. Hence, it creates the need for a precise interwell estimation of lithology and reservoir properties. For this purpose, first the acoustic impedance was obtained by a model-based inversion algorithm. Then, the acoustic impedance attribute and other sample-based seismic attributes were integrated with sand volume and petrophysical data by using multiple attribute regression and neural networks in order to predict Vsand and reservoir property. In the next stage, cross-validation was used to estimate the reliability of the derived multi-attribute transforms. Based on the results of neural networks, the highest cross-correlation was observed between seismic attributes and the observed target logs at seven wells in the study area. After validation, and making a comparison between different available techniques for sand volume, effective porosity and water saturation estimation, multiple regression transform and neural network were used for the first two and latter, respectively. The derived sand volume and reservoir property maps for the Asmari reservoir indicated that high-porous and high-sand volume parts were laterally more continuous in the central and east part of the area under study. In addition, high-porosity zones were more related to high sand volume parts. Based on the result of interpretation and the relationship between core and acoustic impedance, variations in acoustic impedance were related to variations in geological characteristics of Asmari reservoir in the field. Therefore, seismic inversion as a powerful tool can facilitate the detailed studies of sedimentary facies and lithology in the reservoir which contribute to understand the subsurface reservoirs heterogeneities and drilling strategy of future drilling campaigns in the study area.

Reservoir description and characterization of Eni field Offshore Niger Delta, southern Nigeria

Integration of structural and horizon mapping of 3D seismic volume, petrophysical studies of over sixty (60) wireline logs, stratigraphic analyses, reservoir property modeling and production information have been adopted to study Eni field that has been experiencing production decline with increase in water output. Generated reservoir structural framework and spatial reservoir property distribution have proved useful to guide the optimal placement of proposed wells and also provide information needful for the development of best production plan that would guarantee effective oil drainage from the delineated reservoir compartments.

Application of the deterministical and stochastical geostatistical methods in petrophysical modeling, case study Upper Pannonian reservoir, Sava Depression

Deterministic methods are still widely used for reservoir characterization and modelling. The result of such methods is only one solution. It is clear that our knowledge about the subsurface is uncertain. Since stochastic methods include uncertainty in their calculations and offer more than one solution sometimes they are the best method to use. This paper shows testing of the deterministic (Ordinary Kriging) and stochastic (Sequential Gaussian Simulations) methods of reservoir properties distribution in the Lower Pontian hydrocarbon reservoirs of the Sava Depression. Reservoirs are gas- and oil-prone sandstones. Ten realizations were obtained by Sequential Gaussian Simulation, which are sufficient for defining locations with the highest uncertainties of distributed geological variables. The results obtained were acceptable and areas with the highest uncertainties were clearly observed on the maps. However, high differences of reservoir property values in neighbouring cells caused the numerical simulation duration to be too long. For this reason, Ordinary Kriging as a deterministic method was used for modelling the same reservoirs. Smooth transitions between neighbouring cells eliminated the simulation duration problems and Ordinary Kriging maps showed channel sandstone with transitional lithofacies in some reservoirs.

APPLICATION OF ADVANCED APPROACH TO RESERVOIR PROPERTIES DISTRIBUTION AND GEOMETRY PREDICTION FOR COMPLEX TERRIGENOUS RESERVOIRS OF THE CENTRAL DRAGON OILFIELD (VIETNAM)

This paper presents the major results of the research study, including the depositional environments evaluation, lithofacies and petrophysical simulation, and the application of a complex approach to the reservoir properties distribution prediction, reservoir geometry and boundaries estimation in undrilled zones of the Lower Miocene reservoirs of the Central Dragon oilfield (Cuulong basin, Vietnam offshore). These data are actual for further exploration drilling objectives, reservoir stimulation and EOR design.

Linking early diagenesis and sedimentary facies to sequence stratigraphy on a prograding oolitic wedge: The Bathonian of western France (Aquitaine Basin)

To improve the understanding of the distribution of reservoir properties along carbonate platform margins, the connection between facies, sequence stratigraphy, and early diagenesis of discontinuities along the Bathonian prograding oolitic wedge of the northeastern Aquitaine platform was investigated. Eight facies are distributed along a 50 km-outcropping transect in (1) toe-of-slope, (2) infralittoral prograding oolitic wedge, (3) platform margin (shoal), (4) open marine platform interior, (5) foreshore, and (6) terrestrial settings. The transition from shallow platform to toe-of-slope facies is marked in the field by clinoforms hundred of meters long. Carbonate production was confined to the shallow platform but carbonates were exported basinward toward the breakpoint where they cascaded down a 20–25° slope. Ooid to intraclast grainstones to rudstones pass into alternating marl-limestone deposits at an estimated paleodepth of 40–75 m. Three sea-level falls of about 10 m caused the formation of discontinuities corresponding to sequence boundaries. Along these discontinuities, erosional marine hardgrounds formed in a high-hydrodynamic environment at a water depth of less than 10 m, displaying isopachous fibrous cements and meniscus-type cements. The cements pass landward into meniscus and microstalactitic forms along the same discontinuities, which are characteristic of subaerial exposure. During the deposition of transgressive systems tracts, carbonate accumulation remained located mostly on the shallow platform. Energy level increased and carbonates were exported during the deposition of highstand systems tracts forming the infralittoral prograding oolitic wedge. During the deposition of lowstand systems tracts, carbonate production fell to near zero and intraclast strata, derived from the erosion of hardgrounds on the shallow platform, prograded basinward. Early diagenetic cements are related exclusively to discontinuities that are not found within the prograding wedge because of the continuous high sedimentation rate under lower hydrodynamic conditions. This absence of early cementation within the infralittoral prograding oolitic wedge was conducive to porosity conservation, making such features good targets for carbonate reservoir exploration. This study proposes a novel sequence stratigraphy model for oolitic platform wedges, including facies and early diagenesis features.

3-D Geostatistical Model and Volumetric Estimation of ‘Del’ Field, Niger Delta

There is an insatiable thirst for oil and gas consumption and increased production will be made possible only through effective reservoir characterization and modeling. A suite of wire-line logs for four wells from ‘DEL’ oil field together with 3D seismic data were analyzed for reservoir characterization of the field. Two reservoirs were identified using the resistivity log. A synthetic seismogram was generated in order to perform seismic to well tie process as well as picking of horizons throughout the section. Time and depth structural maps were generated. Geostatistical simulation such as the sequential Gaussian stimulation and sequential indicator stimulation were carried out to provide equiprobable representations of the reservoirs, and the distribution of reservoir properties within the geological cells. The modeled reservoir properties resulted in an improved description of reservoir distribution and inter connectivity. The analysis indicated the presence of hydrocarbon in the reservoirs. There is also a fault assisted closure on the structural map which is of interest in exploration. A fluid distribution plot and map of the field were also obtained. The modeled properties gave an average porosity of 24%, average water saturation ranging from 12%-24% and moderate net-gross. The volumetric calculation of the reservoir gives a STOIIP ranging from 37.53 MMbbl-43.03 MMbbl. The result showed high hydrocarbon potential and a reservoir system whose performance is considered satisfactory for hydrocarbon production. The resulting models can also be used to predict the future performance of the reservoir.

Visualisation of geomorphological features and interpretation of the depositional system of the Brewster Member, Ichthys Field

The Brewster Member of the Early Cretaceous Upper Vulcan Formation is one of the main reservoirs of the Ichthys Field. The Brewster reservoir is characterised as massive sandstone, 150–200 m thick, deposited in a deep marine environment. It has a high net sand-to-gross ratio (over 90%) throughout the field, but heterogeneous reservoir quality between the wells. Visualisation of various geo-morphological features from seismic data is critical for the better understanding of the reservoir. Due to thick overburden, frequency content of the seismic volume is limited at reservoir level. Since the reservoir primarily consists of high net sand-to-gross sandstone, and seismic data has limited resolution, it is difficult to identify the various depositional elements using conventional seismic amplitude interpretation. Seismic attribute visualisation techniques were applied to Ichthys 3D seismic and inverted P-impedance data, enabling identification of several geo-morphological features in this otherwise massive sandstone interval (e.g. feeder channel belt, channel-lobe complex, channel-lobe fringe). Core and log scale sedimentological interpretation were tied to the identified feature to understand the depositional architecture of the Brewster Member, which could lead to a better understanding of the distribution of reservoir properties.

Petrophysical Properties Distribution Modelling of an Onshore Field, Niger Delta, Nigeria

This research is based on the modelling of petrophysical parameters distribution of an onshore oil field in Niger Delta. The methodology involves the construction of 3-D grids that represent the reservoir geometry, accompany by property modeling where the 3-D grids were populated with petrophysical properties (porosity, water saturation, net to gross ratio, facies and permeability). The objective is to construct a 3D-dimensional reservoir model that characterizes and evaluate reservoirs in an onshore oil field, Niger delta. Three-dimensional grid and geophysical logs of 4 oil boreholes were used to characterize the delineated reservoirs. Two lithologies and two reservoirs were delineated from the logs. The lithologies are sandstone and mudstone which are arranged in alternation representing the Agbada Formation of the Niger Delta. The calculated petrophysical parameters for the two reservoirs in the four wells were used for estimating the properties distribution in the reservoirs. The petrophysical properties estimation and distribution was done with inverse distance weighting of deterministic techniques of modeling. The calculated porosity values for the two reservoirs range from 0.061 to 0.30 with an average of 0.185. The permeability of the two reservoirs ranged from 110 to 2394 mD. The calculated water saturation and net to gross ratio of the two reservoirs range from 0.23-0.57 with an average of 0.4 and 0.44-0.87 with an average of about 0.61 respectively. The porosity, permeability, water saturation and net to gross ratio and facies models show uniform distribution within the reservoirs. From the models, it can be inferred that the reservoir properties within the central part of the field are very good. It is, therefore, advisable that wells should be drilled in the central region to investigate the presence of oil. The results of this study have shown the effectiveness of 3D reservoir modeling as a tool for understanding the spatial distribution of reservoir properties. The results can be used as a guide for evaluating future performance and production behavior of the reservoirs.

Synthetic Fractal Modelling of Heterogeneous and Anisotropic Reservoirs for Use in Simulation Studies: Implications on Their Hydrocarbon Recovery Prediction

Optimising production from heterogeneous and anisotropic reservoirs challenges the modern hydrocarbon industry because such reservoirs exhibit extreme inter-well variability making them very hard to model. Reasonable reservoir models can be obtained using modern geostatistical techniques, but all of them rely on significant variability in the reservoir only occurring at a scale at or larger than the inter-well spacing. In this paper we take a different, generic approach. We have developed a method for constructing realistic synthetic heterogeneous and anisotropic reservoirs which can be made to represent the reservoir under test. The main physical properties of these synthetic reservoirs are distributed fractally. The models are fully controlled and reproducible and can be extended to model multiple facies reservoir types. This paper shows how the models can be constructed and how they have been tested. Reservoir simulation results of a number of generated 3-D heterogeneous and anisotropic models show that heterogeneity, in terms of only the geometric distribution of reservoir properties, has a little effect on oil production from high and moderate quality reservoirs. However, if the effect of heterogeneity on capillary pressure is taken into account, the effect becomes striking, where varying the heterogeneity of reservoirs properties can lead to a 70 % change in the predicted oil production rate and a significant early shift of water breakthrough time. Hence, it is the heterogeneity consequences that are really substantial if not taken into account. These are very significant uncertainties for a hydrocarbon company if the heterogeneity of their reservoir is not well defined.

Seismic reservoir characterization using the multiattribute rotation scheme: Case study in the South Falkland Basin

Estimating information about reservoir properties from seismic data is a key challenge in exploration and in the appraisal and production of hydrocarbons. We discuss how to perform quantitative reservoir characterization by integrating well-log and seismic-inversion data through the application of the multiattribute rotation scheme (MARS). This method is a hybrid rock-physics/statistical approach that uses a global search algorithm to estimate a customized transform for each geologic setting in order to predict petrophysical properties from elastic attributes. The transform is computed using measured and/or rock-physics-modeled well-log information and is posteriorly applied to seismically derived elastic attributes to predict the spatial distribution of petrophysical reservoir properties. This workflow was applied on the Darwin Field, located in the South Falkland Basin, which consists of two adjacent tilted fault blocks: Darwin East, which contains the discovery well 61/17-1, and Darwin West, which remains untested. The resulting rock-property volumes (water saturation, clay content, and total porosity) characterize the heterogeneity of the reservoir and were used to delineate the extension of the proven reservoir and to delineate other potential plays in the area. In addition, these property volumes can be used as inputs for static model generation and reserve estimation, as well as to optimize the exploration and exploitation plan for the area.

The National Risk Assessment Partnership’s integrated assessment model for carbon storage: A tool to support decision making amidst uncertainty

The US DOE-funded National Risk Assessment Partnership (NRAP) has developed an integrated assessment model (NRAP-IAM-CS) that can be used to simulate carbon dioxide (CO2) injection, migration, and associated impacts at a geologic carbon storage site. The model, NRAP-IAM-CS, incorporates a system-modeling-based approach while taking into account the full subsurface system from the storage reservoir to groundwater aquifers and the atmosphere. The approach utilizes reduced order models (ROMs) that allow fast computations of entire system performance even for periods of hundreds to thousands of years. The ROMs are run in Monte Carlo mode allowing estimation of uncertainties of the entire system without requiring long computational times. The NRAP-IAM-CS incorporates ROMs that realistically represent several key processes and properties of storage reservoirs, wells, seals, and groundwater aquifers. Results from the NRAP-IAM-CS model are used to quantify risk profiles for selected parameter distributions of reservoir properties, seal properties, numbers of wells, well properties, thief zones, and groundwater aquifer properties. A series of examples is used to illustrate how the risk under different storage conditions evolves over time, both during injection, in the near-term post injection period, and over the long term. It is also shown how results from NRAP-IAM-CS can be used to investigate the importance of different parameters on risk of leakage and risk of groundwater contamination under different storage conditions.

Simultaneous History-Matching Approach by Use of Reservoir-Characterization and Reservoir-Simulation Studies

Summary Reservoir characterization is the key to success in history matching and production forecasting. Thus, numerical simulation becomes a powerful tool to achieve a reliable model by quantifying the effect of uncertainties in field development and management planning, calibrating a model with history data, and forecasting field production. History matching is integrated into several areas, such as geology (geological characterization and petrophysical attributes), geophysics (4D-seismic data), statistical approaches (Bayesian theory and Markov field), and computer science (evolutionary algorithms). Although most integrated-history-matching studies use a unique objective function (OF), this is not enough. History matching by simultaneous calibrations of different OFs is necessary because all OFs must be within the acceptance range as well as maintain the consistency of generated geological models during reservoir characterization. The main goal of this work is to integrate history matching and reservoir characterization, applying a simultaneous calibration of different OFs in a history-matching procedure, and keeping the geological consistency in an adjustment approach to reliably forecast production. We also integrate virtual wells and geostatistical methods into the reservoir characterization to ensure realistic geomodels, avoiding the geological discontinuities, to match the reservoir numerical model. The proposed methodology comprises a geostatistical method to model the spatial reservoir-property distribution on the basis of the well-log data; numerical simulation; and adjusting conditional realizations (models) on the basis of geological modeling (variogram model, vertical-proportion curve, and regularized well-log data). In addition, reservoir uncertainties are included, simultaneously adjusting different OFs to evaluate the history-matching process and virtual wells to perturb geological continuities. This methodology effectively preserves the consistency of geological models during the history-matching process. We also simultaneously combine different OFs to calibrate and validate the models with well-production data. Reliable numerical and geological models are used in forecasting production under uncertainties to validate the integrated procedure.

Integrated Reservoir Characterization and 3D Modeling of the Monteith Formation: A Case Study of Tight Gas Sandstones in the Western Canada Sedimentary Basin, Alberta, Canada

SummaryThe Monteith Formation is an important tight gas reservoir in the Deep Basin, Alberta, and consists of a progradational succession of shallow marine sediments, nonmarine carbonaceous and coaly, coastal plain facies, and coarse-grained fluvial deposits, from base to top, respectively. This study is based on multiscale description and characterization techniques with cores and drill cuttings, including multimethods laboratory measurements of key reservoir parameters such as porosity and permeability. A second stage of the study involves the use of laboratory measurements obtained from cores and drill cuttings and their integration with well logs to construct a numerical 3D model of the study area. The 3D model is used to history match gas production, and forecast performance of new wells in those areas where the geologic model indicates potential for gas production.The ultimate goal is to provide a better understanding of the distribution of reservoir properties in the study area for developing drilling prospects and their production potential in areas where reliable data are scarce. The reservoir-modeling stage is carried out by implementing a recently developed methodology that integrates a variable shape distribution (VSD) model, capable of capturing different reservoir properties throughout the whole scale spectrum without any data truncation. Truncation is the excuse generally used for eliminating information that does not fit a given distribution. The claim is that the data are of poor quality, something that is not true in many cases. This new methodology eliminates the need for truncation, and introduces an extension of the VSD approach for reservoir-simulation purposes that reduces uncertainty in the generation of drilling prospects.Core analysis shows that the Monteith A member is composed of complex fluvial-dominated deposits with better rock quality than the shallow marine sandstones of the Monteith C member. This is most likely because of larger pore-throat apertures that range between 0.5 and 1 μm, and a relatively higher proportion of preserved intergranular pore space within these coarser-grained framework grains. Furthermore, the best production performance is from wells that are producing from the Monteith A. Variability of production rates also seems to be controlled by the presence of natural fractures. It is anticipated that the resulting 3D reservoir model will allow improving field-development strategies for this and other similar unconventional gas reservoirs in the Deep Basin of Alberta and elsewhere.

3-D geological modeling for tight sand gas reservoir of braided river facies

Abstract Considering the poor applicability of conventional geological modeling to tight sand gas reservoir in braided river facies, a modeling method of “multi-stage constraints, hierarchical facies control and multi-step modeling” was put forward taking Sulige gas field in Ordos Basin as the study object. The method obtains the GR field by seismic inversion constrained by logging data, and GR model is built under the control of the prior geological knowledge; the relation regression is realized between the GR model and the sandstone probability, sandstone probability model is built, and rock facies model is obtained by multi-point geostatistics theory; sedimentary microfacies model controlled by rock facies and braided-river-system is made; and eventually an effective sand body model is built by integrating sedimentary microfacies, effective sand body scale and reservoir properties distribution. The research method discussed in this paper has put geological constraints into the model as far as possible, enhanced the inter-well sand body predictability and improved the precision rate, thus it can provide a more reliable geological basis for gas reservoir development.

3D Stochastic Modeling for Reservoir Characterization and Application

The reservoir is the accumulation spaces and development targets of hydrocarbon, always draw attention of researchers who participated in hydrocarbon exploration and development. The goal of reservoir characterization is to delineate precisely and completely the geologic variations for reservoirs in 3D distribution by the application of all kinds of useful data channel, so that it can give a reliable reference for the further reservoirs development. However, stochastic modeling has become the dominant tool for reservoir characterization because it can both simulate the reservoir heterogeneity and quantitatively characterize reservoir. Aimed at reservoirs in well block X26-X27 of Xiazijie Oilfield, on basis of reservoir structure, sedimentary microfacies, logging interpretation and reservoir heterogeneity research, the geologic dataset is established, and the 3D models, such as reservoir structure, logging interpretation and reservoir attributes, were all worked out by the application of stochastic modeling technique and 3D visualized technique to this area, furthermore, the testing and modification for facies analysis and classification were conducted in order to unravel the consistent micro-facies and reservoir property distribution, so that it will serve well for the identification and fine description and reservoir dynamic simulation.

A multiresolution adjoint sensitivity analysis of time-lapse saturation maps

Improvements in seismic data acquisition and processing have made seismic technology a viable source of information for locating hydrocarbon deposits and also for describing the spatial variability of reservoir parameters. While three-dimensional seismic technology is already a well-established means of locating hydrocarbon deposits, the 4D (or time-lapse) seismic is gradually becoming a source of reservoir parameter description. In particular, time-lapse seismic is increasingly becoming a useful source of information about fluid migration and pressure changes in the reservoir. In recent years, time-lapse seismic data or saturation maps derived from such data have been used to estimate spatial distribution of reservoir parameters through history matching. However, successful application of the method to accurate description of reservoir parameter variability remains a challenge. Some major challenges in the application of time-lapse seismic data in reservoir model history match are the poor resolution of the seismic data, uncertainty associated with the maps of changes in saturation derived from the seismic data, and the massiveness of the data or the associated saturation maps. Repeat seismic data are blurred or low-resolution maps of trends in reservoir responses to production and injection activities. These trends are influenced by reservoir property distribution and when used judiciously, constitute a good source of information that can help in reducing the uncertainty associated with reservoir parameter estimates. The maps of changes in reservoir saturation or pressure obtained from repeat seismic data are themselves fraught with uncertainties and care must be taken when using these maps to estimate reservoir parameters. Furthermore, obtaining the most useful information from a voluminous seismic data set is challenging and is still an active area of research. In this work, we present the use of the wavelet transform to integrate maps of changes in reservoir saturation derived from time-lapse seismic data into reservoir model history matching. The work involves transforming the saturation-change map into a wavelet space and then history matching some carefully selected wavelets to obtain estimates of reservoir parameters. Three sample applications based on synthetic data are used to show the suitability of the approach. Comparison is made to conventional approach in which the saturation-change map is not transformed into wavelets before matching.

Spatial stochastic modeling of sedimentary formations to assess CO2 storage potential.

Carbon capture and sequestration (CCS) is a technology that provides a near-term solution to reduce anthropogenic CO2 emissions to the atmosphere and reduce our impact on the climate system. Assessments of carbon sequestration resources that have been made for North America using existing methodologies likely underestimate uncertainty and variability in the reservoir parameters. This paper describes a geostatistical model developed to estimate the CO2 storage resource in sedimentary formations. The proposed stochastic model accounts for the spatial distribution of reservoir properties and is implemented in a case study of the Oriskany Formation of the Appalachian sedimentary basin. Results indicate that the CO2 storage resource for the Pennsylvania part of the Oriskany Formation has substantial spatial variation due to heterogeneity of formation properties and basin geology leading to significant uncertainty in the storage assessment. The Oriskany Formation sequestration resource estimate in Pennsylvania calculated with the effective efficiency factor, E=5%, ranges from 0.15 to 1.01 gigatonnes (Gt) with a mean value of 0.52 Gt of CO2 (E=5%). The methodology is generalizable to other sedimentary formations in which site-specific trend analyses and statistical models are developed to estimate the CO2 sequestration storage capacity and its uncertainty. More precise CO2 storage resource estimates will provide better recommendations for government and industry leaders and inform their decisions on which greenhouse gas mitigation measures are best fit for their regions.

Static Reservoir Modeling Using Well Log and 3-D Seismic Data in a KN Field, Offshore Niger Delta, Nigeria

This study focuses on the application of 3D static model using 3-D seismic and well log data for proper optimization and development of hydrocarbon potential in KN field of Niger Delta Province. 3D Seismic data were used to generate the input interpreted horizon grids and fault polygons. The horizon which cut across the six wells was used for the analysis and detailed petrophysical analysis was carried out. Structural and property modeling (net to gross, porosity, permeability, water saturation and facies) were distributed stochastically within the constructed 3D grid using Sequential Gaussian Simulation and Sequential Indicator Simulation algorithms. The reservoir structural model show system of different oriented growth faults F1 to F6. Faults 1 and Fault 4 are the major growth faults, dipping towards south-west and are quite extensive. A rollover anticline formed as a result of deformation of the sediments deposited on the downthrown block of fault F1. The other faults (2, 3, 5 and 6) are minor fault (synthetic and antithetic). The trapping mechanism is a fault assisted anticlinal closure. Results from well log analysis and petrophysical models classified sand 9 reservoir as a moderate to good reservoir in terms of facies, with good porosity, permeability, moderate net to gross and low water saturation. The volumetric calculation of modeled sand 9 horizon reveals that the (STOIIP) value at the Downthrown and Ramp segment are 15.7 MMbbl and 3.8 MMbbl respectively. This implies that the mapped horizon indicates hydrocarbon accumulation in economic quantity. This study has also demonstrated the effectiveness of 3-D static modeling technique as a tool for better understanding of spatial distribution of discrete and continuous reservoir properties, hence, has provided a framework for future prediction of reservoir performance and production behavior of sand 9 reservoir. However, more horizontal wells should be drilled to enhance optimization of the reservoir.

Impact of multiscale modelling on predicted porosity and permeability distributions in the fluvial deposits of the Upper Lunde Member (Snorre Field, Norwegian Continental Shelf)

Abstract Models of hydrocarbon reservoirs are often used to support management decisions about field development and redevelopment. Typical modelling workflows result in a reservoir and simulation model with a property distribution generally comparable to the well data, and this is often considered sufficient. The current study tests this assumption on the fluvial reservoir in the Upper Lunde Member of the Snorre Field where sedimentary heterogeneities at multiple scales influence reservoir properties such as porosity and permeability. This work shows that, by describing and modelling the sedimentary heterogeneities at several length scales in the reservoir, and by using a flow-based local upscaling method, the resulting porosity and permeability distribution at the scale of the reservoir and simulation model are significantly different from porosity and permeability distribution at the well data scale; the variance tends to reduce and, for permeability, the distribution type is changed from log–normal to normal. Reservoir property distributions based on multiscale modelling, sensitive to the representative elementary volumes for permeability, and upscaled in a realistic sedimentological framework, give a better representation of the effective permeability architecture.

Geological Characteristics of Viscous Reservoirs & Mining Safety Technical in Northern Tibet Plateau

According to geological characteristics and the occurrence of heavy oil properties in the northern Tibetan plateau, the development feasibility studies and risk analysis were carried out . A detailed examination of the effects of diagenesis were conducted in terms of microcopic observation , stratigraphic facies and other low permeability reservoir aspects. The main factor affecting reservoir properties was theorized. Finally, the reservoir development risk is illustrated. Measures of the reservoir protection and efficient exploitation were presented. The results show that diagenetic compaction and cementation makes greate impact on the reservoir properties distribution .And it is recommended to use the steam stimulation method test mining , the method is less investment , the technology is simple , fast yield , good economic returns .