Three-dimensional fracture networks, combined from seismic scale to wellbore scale, can greatly enhance the knowledge of fracture contribution to hydrocarbon storage and flow inside the reservoir. This paper presents some techniques used at ENI-Agip for fracture network simulation at wellbore scale. First, new imaging techniques adopted for enhancing and facilitating the data acquisition from orientated cores will be shown. We will discuss how the fracture data, acquired from the combined analysis of orientated core and wellbore image logs, have to be processed in order to calculate the geometrical parameters of each feature (dip direction, dip, size, terminations) and to classify them according to their filling (oil, water, shale, calcite, etc.). Second, we will illustrate how these kind of data are processed in order to extract the fracture representative parameters needed for stochastic simulation of fracture network at the wellbore scale: spatial distribution along the cored/logged interval, number of fracture sets, representative orientation and statistical distribution of each set, distribution laws of the fracture length and relevant minimum radii and fracture aperture estimate. Fracture porosity evaluation, matrix block size, fracture network connectivity at wellbore scale constitute the outputs of such simulations: they are used to better characterize a fractured reservoir and to describe its behaviour. The synthetic results of the application of such a methodology on a real case (tight packstone/wackestone of carbonate platform from a southern Apennine italian oil reservoir) complete the paper.The main target of the reservoir geologist is the petrophysical characterization of the reservoir in order to estimate: 9 the original hydrocarbons in place; 9 the fluid flow path; and thus 9 the reserves.The building of a geological model, which reasonably describes the lateral and vertical variations of the petrophysical characteristics, i.e. porosity, permeability and hydrocarbon saturation, stands at the root of these estimates. The hydrocarbons in place are, in fact, estimated on the basis of this geological model, and very often a three-dimensional (3D) numerical model, which schematically represents the geological reality, is built in order to estimate the reserves.The petrophysical characterization of fractured reservoirs is more complicated than conventional non-fractured reservoirs because of the presence of two different pore systems: the matrix pore system and the fault-fracture network pore systemThe recognition of the presence of a fracture network is, therefore, crucial because it has a significant effect on reservoir fluid flow. Considering values of fracture porosity that become progressively more significant when compared to the matrix porosity, there are four ways in which fractures can affect a reservoir. Schematically, four types of reservoir can be recognized according to the different contribution of fractures: type 1: type 2: type 3: type 4: fractures impart no positive reservoir quality bu...
The gas-condensates-oil reservoir of the Karachaganak Field, Pri-Caspian Basin, Kazakhstan, consists of carbonates forming a low angle ramp in the Tournaisian-Early Visean, an isolated carbonate bank in the Late Visean-Bashkirian and a high-rising isolated build-up in the Early Permian (Asselian-Artinskian). The reservoir, sealed by Kungurian-Ufimian-Kazanian evaporites, is overlain by three salt diapirs that make the reservoir seismic imaging challenging and the use of pre stack depth migration seismic mandatory for interpretation. Following the depth reprocessing of the seismic acquired in 1999, and as a consequence of the remarkably imaging improvements achieved, a revision of the Early Carboniferous reservoir stratigraphic architecture has been recently carried out. Its ultimate goal is to provide elements (internal stratigraphy, depositional facies and dolomite distributions) for the reservoir model updates, for the day by day drilling follow-up and for the future wells planning. The work integrated the definition of a 3D full field seismosequence stratigraphy framework with the analysis of the available wellbore data. The Carboniferous interval, bounded by the Devonian-Carboniferous PV2 unconformity at the bottom and by the Carboniferous-Permian C1a unconformity at the top, was identified as a high rank sequence and internally subdivided in six mid rank sequences (Early Tournaisian, Early Visean, Late Visean, Serpukhovian I, Serpukhovian II and Bashkirian) bounded by mid rank sequence boundaries (PV1b -Top Early Tournaisian, Top Bobrikovsky, C7 -Top Late Visean, ILS -Intra Late Serpukhovian and C1b -Top Serpukhovian), either recognized from well data only or identified on seismic and correlated to unconformities recognised on wells. Within this interval, the high rank transgressive section includes Tournaisian and Early Visean ramp carbonates delimited at the top by a regional marker of shale and cherty limestone that records the maximum sea level (C9 -Tula, high rank maximum flooding surface). The Late Visean and Serpukhovian high rank highstand section records the onset of biohermal deposits, and a phase of remarkable vertical growth, characterized by aggrading, prograding and downstepping internal geometries, well imaged by the reprocessed seismic depth cube. The Serpukhovian evolution has been mapped over the entire Field and the relevant seismic horizons (Top SERP AGG1, Top SERP AGG2, Top SERP PROG1, Top SERP PROG2, Top SERP PROG3 and Top SERP PROG4) have been interpreted, in terms of sequence stratigraphy, as the seismic response of low rank sequence boundaries marking the top of shallowing upwards cycles (recognized from logs and core facies interpretation). This was confirmed by the high resolution cross-well seismic profiles acquired along the northern margin of the carbonate bank. The stratigraphic architecture presented in this study provides elements to explain the reservoir behaviour, and particularly the effects of dolomitisation.
In this work, we address the challenge of modelling a complex, carbonate reservoir, where the fractures network, connected throughout a complex fault framework, represents large part of both the storage and the flow capacity of the system. The asset is a giant, onshore field, developed since the 90's by primary depletion through several horizontal wells, targeting anomalous fluid columns. Different culminations are characterized by specific production drive mechanisms. The objective is to integrate an impressive amount of data into a digital model, suitable to understand fluid flow behavior and support decision. The field is challenging in every geological and dynamic feature. The reservoir complexity ranges from the intricate structural framework (several hundreds of reverse faults), to the puzzling fractures network at different scales, to the unclear role of the low-porosity rock matrix, to the heterogeneous distribution - both laterally and vertically - of fluid properties, related to different combinations of hydrocarbon and acid components. The workflow is based on the adoption of Volume Based Modelling (VBM) to account for seismic faults. Then, large-scale fractures are modelled using a blend of stochastic and deterministic Discrete Fracture Networks (DFNs), while background fractures (BGF) are characterized using a Continuous Fracture Modeling (CFM) formulation. A Dual Porosity - Dual Permeability (DPDK) approach is then implemented for reservoir simulation. The model is finally reconciled with the production data by iterating between geology and simulated dynamic response. The whole modeling and simulation workflow, from static to dynamic model definition, is developed relying on company's top-class computational resources. The DPDK formulation, where DFN is the second medium while the first medium consists of BGF and rock matrix, allows us to simulate the main production mechanism: large-scale discontinuities – DFN – are withdrawal first, and then fluid is recharged by smaller scale features. Besides, the history matching phase, together with accurate production and Pressure-Volume-Temperature (PVT) data analysis, sheds light on the extreme heterogeneity of the field. Petrophysical properties, storage and effective apertures of discontinuities are calibrated according to the production history, and integrated into a comprehensive understanding of the reservoir. Eventually, we reveal how a robust history matched model may be used as a powerful tool to understand the impact of all the involved criticalities on the subsurface fluid behavior and movement in a complex fractured carbonate setting. The challenges addressed in this work provide relevant best practices for carbonate reservoir modelling, in particular highlighting the role of the integration between geology and reservoir engineering to minimize subsurface uncertainties. Furthermore, the PVT model developed in this study proposes new migration scenarios to explain the sour gas distribution. Finally, optimized procedures to tackle numerical criticalities using advanced reservoir simulators are disclosed.
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