Summary In fractured reservoirs, data directly related to fractures are scarce and 1D (e.g., core and image-log data). Other types of data are more widespread (e.g., seismic data) but generally are related only indirectly to fracture distribution. In such reservoirs, it is necessary to understand and then to model the fracture network on a field-wide scale by integrating all available data. We propose a methodology to achieve this objective. The methodology establishes relationships between the fracturing and other sources of data in a systematic workflow that goes from static 1D data to a 3D dynamic model. The methodology is described and illustrated with a case study from north Africa. In this field, fracture data from image logs and cores are related to (1) 3D seismic attributes (e.g., amplitude, coherency), (2) fault patterns, and (3) other types of well data (e.g., interval thickness, lithology index, and porosity). Production data also are used to quantify the contribution of each fracture set to flow, which then can be mapped on a reservoir basis with the more widely distributed log and seismic data. The resultant set of maps then is entered into a dynamic reservoir model. The methodology has been validated with a new well, the fracture network of which was accurately predicted in the reservoir by the model.
In fractured reservoirs, data directly related to fractures are scarce and uni-dimensional (i.e. cores and image logs). Other types of data are better distributed and have proved to be related to fracturing but only indirectly (e.g. lithology or large scale structure). In such reservoirs, however, one has to understand fracture distribution and behavior at the field scale. A methodology has been developed within TotalFinaElf to define the relationships of all sources of data to fracturing and to integrate them and compared to another independent published method. To that end, a systematic work flow which goes from 1D to 2D and from static to dynamic data has been defined and various technologies tested. A field case in North Africa is taken to illustrate this methodology. In this field, fracture data from image logs have been related to: production data; 3D seismic attributes (coherency, amplitude, structural curvature) and fault interpretation and strain; log data such as porosity, thickness and lithology index. The former type of data is used to understand the contribution of each fracture set to flow. The latter two types of data are used to better map fracture distribution at the field scale. Ultimately, this mapping is calibrated with the production data of the other wells where fracturing data are not available and is then used to validate the specific role of fracturing in this field. A better reservoir simulation and infill well planning can be subsequently achieved. Introduction Fractured reservoirs are by nature highly heterogeneous. In such reservoirs, fracture systems control permeability and can also control porosity. Fracture modeling is therefore a key development issue and requires an integrated approach from geology to reservoir simulation and well planning. The geometry (i.e. static model) of the fracture network is generally defined from well data (i.e. cores or image logs) using conventional structural geology techniques. Then, fracture permeability can be assessed by relating the fracture aperture to the fracture excess conductivity measured on electrical image logs1 and/or to critically stressed fractures within the present day stress field2. However, it is the authors' opinion that such approaches can only give, in the best case, a relative estimate of the fracture permeability. A quantitative modeling of fracture flow behavior is therefore required (i.e. dynamic model). At the well scale, this can be done by constructing Discrete Fracture Networks (DFN)3–4 through which flow is modeled and which are matched to well test data5. Ultimately, these models can help in determining the fracture parameters required in dual porosity / dual permeability reservoir flow simulation6,7. However, if these DFN models are appropriate for reservoir sector models, their application to full field simulation is somewhat difficult since their extrapolation outside the well scale can be limited by the heterogeneous vertical and lateral distribution of the fracture networks. The modeling of the spatial distribution of fracturing at the scale of the entire field and its calibration to well data is the purpose of this paper.
The calculation of effective flow properties of naturally fractured reservoir (NFR) has been the purpose of research works for many years. Based on a static characterization of the fracture system (orientations and densities), equivalent flow properties provide continuum representations of discrete systems from which multiphase flows can be simulated using dual-permeability and dual-porosity models. Common flow properties include anisotropic permeability tensors attached to the fracture system itself, and block sizes or shape-factors, which characterize the capability of the fracture and matrix media, to exchange fluids.Analytical and numerical calculation methods are now proposed by different commercial software tools, or have been the purpose of in-house developments. All methods rely on some conceptual models that are necessarily simplified representations of actual fracture systems, both complex and very partially known. Whether the underlying conceptual models are relevant certainly depends on the particular features of each fracture system. More important is the capability of models to capture features that are consequential for reservoir production. Only then can one expect to build meaningful NFR models likely to be calibrated to match production history data and to perform reliable reservoir forecasting. The CPU-time or memory requirements of implemented methods may also be a concern, as potentially relevant methods or software are unable to get through the calculations when full-field modelling is required. It follows that the comparison and validation of equivalent flow-property calculation methods and NFR modelling software is anything but an easy task. As a first contribution to this end, we review and compare several equivalent permeability calculation methods available from two commercial software suites and from our own proprietary tool (GoFraK). We first present the numerical and analytical methods that were tested, including the original ones we developed which were expected to show better calculation and speed performances. We then detail the realistic benchmark case studies used to compare the different methods, from the calculation of equivalent flow properties to the multiphase flow simulation of forecast production. The results are finally presented and discussed. They show that the numerical methods offered by commercial products, based on 3D discrete fracture networks (DFN) to compute equivalent permeability tensors, are generally unable to manage full-field models, and that their simpler analytical methods are to be used with great caution because of important underlying assumptions. These results also validate the approach and methods we developed in GoFraK and demonstrate their robustness and efficiency. Multiphase flow simulations were carried out to evaluate the impact of dual-media models on production forecast. They confirm that permeability tensors are not the only important effective flow properties, block sizes and more generally fracture/matrix transfer functions being also hig...
In the oil bearing reservoirs of a mature field in the offshore Abu Dhabi, the understanding of the fracture network is essential with growing gas and water productions. Fracture characterization and modeling at the full field scale is the key to match the production profile and to optimize infill drilling. The interpretation of fracture data from image logs and cores allows defining accurately the fracture pattern in terms of orientation, typology, density and relation with lithology and faulting. Two main fracture sets are chronologically observed:NW-SE fractures are generally mineralized and clustered around faults of similar orientations;NE-SW fractures are generally open, homogeneously distributed with their density controlled by the lithology and a few portion located in swarms. The calibration of fracture data with PLT's in horizontal drains suggests that:the main flow comes from the matrix in porous layers;in areas without mineralized fractures, wells can be connected to water, either through matrix (permeable layers) or through open NE-SW fractures, particularly in zones of large curvature where a higher fracture density is expected;in areas with mineralized fractures, water in permeable layers is channelized and tight layers can be vertically connected to more permeable layers by open fractures whereas the lateral flow can be hampered. Full field fracture modeling is done through an innovative geostatistical approach. First, discriminant analysis is used to derive, from geological attributes that are known to be physically related to fracturing, a (geological) component best correlated to well fracture data. Second, sequential indicator simulation generates equiprobable fracture density maps. Third, optimization of infill drilling is made through risk analysis. The pertinence of this approach for the optimization of well planning is validated against recently drilled wells. Matching the production profile is made more difficult however by the different opening times of production wells and by their complex completions. Introduction The oil bearing field under study was discovered in 1969 and put on stream in 1973. In 1979 a water injection scheme was launched followed by a gas injection development; first pilot in 1991 then full field starting 1997. To date, more than 120 wells were drilled including several horizontal drains. Although fractures were identified in this field at an early stage, their contribution to field performance was not initially considered as important. However, with the decline of the field and the water and gas injection programs, well behaviors showed that this early statement should be revisited. Indeed, the impact of fracture systems on such mature carbonate reservoirs can range from very restricted to conduit for fluid flow and reservoir impairment. This impact does not depend only on the type of fracture filling but also on fracture geometry, connectivity and density. According to the full field distribution of the fracture pattern, the three above impacts are possible. Consequently, only the characterization of all fracture parameters can lead to a comprehensive fracture model. This fracture model needs to be evaluated against dynamic data and the spatial distribution of fractures at the entire field scale is required to improve field development plans. The model can be also evaluated against new data and revised if necessary. This is the purpose of this paper.
fax 01-972-952-9435. AbstractA large proportion of petroleum reservoirs is known to be naturally fractured with consequences on their flow behavior hence on reservoir performance. Though the modeling of such reservoirs has been the purpose of many research works, it remains a challenging task. Too simplistic reservoir models do not allow capturing essential features like large-scale fracturing trends, or non-linear multivariate relationships between the equivalent (generally anisotropic) permeability of the fracture system, and fracture densities and properties to be characterized on a directional fracture-set basis. Conversely, too complex reservoir models, intended to be more realistic, require computationally intensive and memory consuming algorithms. They also involve numerous parameters, a large part of which cannot be estimated from available data.In-between, there is a need for reasonably complex models and methods to generate them in a consistent way with various fracturing and dynamic data in order to produce conditional models. This paper presents such an approach, which has been developed as a workflow.The approach is based on an original conceptual model of fracture systems and a notion of scale-dependent effective properties. It is also a two-step modeling approach in which the fracture system is first characterized, then converted into equivalent flow properties for reservoir simulation purposes. Key aspects of the approach include the geostatistical modeling of fracture densities, scale-dependent calculation of equivalent within-layer horizontal permeability tensors based on spatially periodic discrete fracture networks, analytical calculations of vertical inter-layer permeabilities, and conditioning to well-test permeabilities by using steady-state flow-based evaluation of reservoir model responses. All these aspects rely on innovative and CPU-time efficient methods. They are introduced and illustrated by case-study results.
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