Second EAGE Workshop on Naturally Fractured Reservoirs

Understanding the main mechanisms controlling fault and fracture impedance across different lithologies is an important factor to estimate the flow properties and recovery of geo-fluids in frac-tured reservoirs. A multidisciplinary study of the Cretaceous carbonate platform of the Maiella Moun-tains allowed concluding on the occurrence and impeding mechanism of two main mechanical boundaries for large-scale fractured zones. Additionally, a workflow for applying the outcrop findings to the subsurface has been described and illustrated. The two identified mechanical boundary types are related to porous, well-sorted bioclastic packstone/grainstone units and dolomitized layers respectively. The first type occurs within the Upper Cretaceous succession in an open platform environment, whereas the second type was found within the Lower Cretaceous deposits of a more restricted environment. Depending on its sequence strati-graphic position at/above flooding surfaces, the packstone/grainstone related mechanical boundary occurs at the base of 50-80m thick cycles. A method to record both mechanical boundary types in the subsurface with a fracture impedance of 100% through the analysis of borehole image and other well logs is described. Subsequent upscaling of the generated fracture impedance logs, the interpolation of upscaled logs and the conversion of relative fracture impedance into vertical transmissibility multipli-er arrays is finally described.

Natural fractures bear significant influence on productivity in Tengiz field, which is one of several giant light-oil accumulations trapped in isolated carbonate platforms in the Pricaspian Basin of Kazakhstan. Outcrop analogs are particularly important for understanding reservoir fracture systems because many aspects of fracture character (e.g. height, length) are impossible to measure with subsurface data. The Devonian margin of the Canning Basin in NW Australia presents a well-exposed outcrop analog for steep margin and slope deposits of Tengiz field. Fracture data gathered from Tengiz core and image logs suggest affinity to fractures in the Canning outcrops in terms of origin, orientation, and range of density. Inclusion of additional information - gained through outcrop study - into reservoir fracture description leads to improved understanding of stratigraphic influence on their occurrence and character. Shallow-burial fractures – those formed in carbonate strata prior to significant burial, including neptunian fractures – are the most important for reservoir productivity at Tengiz field. These fractures dip steeply and strike dominantly parallel and/or normal to the local orientation of the depositional margin. They are most well-developed in brittle, boundstone-dominant facies of the outer-platform to upper slope environment. Dissolution by corrosive fluids following burial led to enlargement of fracture apertures, which range from small to cavernous. In Tengiz field, cavernous fractures pose both high lost-circulation risk, as well as the reward of highly productive wells. Outcrop data from the Canning Basin show fractures in the mid- to upper-slope facies and reef core are, on average, not limited by bedding and hence much taller than fractures in the reef flat and outer platform areas. Fracture size cumulative distributions are mainly exponential, and they differ between stratigraphic settings. We expect such size differences will have important effects on fracture connectivity and permeability in a reservoir. Fracture density, which is measured routinely in the Tengiz reservoir, was measured with long pseudowells (i.e. scanlines) “drilled” along Canning outcrops. Fracture density shows significantly less variation among facies than does fracture height. Thus, outcrop-based data can add substantially to our understanding of key fracture system characteristics that are unavailable from well data alone.

Geomechanical concepts and approaches are associated with many aspects of fractured reservoirs. It is convenient to consider two main contexts: those where the goal is to understand the formation of the trap and its fracture system, and those where the goal is to predict or explain production performance. The practical justification for efforts aimed at understanding the pre-production history of the reservoir is that some or most of the learnings from this are to be used to inform the production evaluation/prediction efforts. The geological evolution of the trap considers aspects such as the tectonic cause of the reservoir’s shape, and how deformation processes operated to create fracture networks. These considerations often lead to the recognition that fractures may terminate against other fractures, but often do so at bedding contacts, leading to a conclusion that the pre-deformation vertical arrangement of rock types and their properties is an important control, along with the deformation-caused curvature or distortion of the initially-planar rock succession. The use of fracture observations for predicting reservoir performance can take several forms: from their use to estimate spatial variations of a static equivalent permeability, to the creation of explicit fracture network models with the potential for production-related changes in fracture opening, to methods that aim to calculate fully-coupled interactions between the mechanical state and the porefluid changes. Natural fracture arrays, as seen in outcrop analogues, can range from simple patterns composed of one or two sets, to complex networks whose genesis is not simply explained. The common concepts used to explain fracture formation are based on stress states, but this conceptual framework leads to difficulties in explaining complex networks, which may show overlapping creation and movement on the discontinuities belonging to many fracture sets (Fig. 1). An alternative conceptual framework focuses on fracture arrays in terms of the strain states that they define, and relegates stress to being a local indicator of instantaneous load-carrying arrangements that evolve during fracture creation and trap growth. This framework, with its emphasis on strain accumulation by fractures, provides the understanding needed to inform reservoir prediction.

The behavior of fractures during production makes fractured reservoirs unique in terms of flow behavior and reservoir’s response to in-situ stresses. While the behavior of other reservoirs is controlled by textural properties of matrix, the behavior of fractured reservoirs is driven by anisotropy depending upon the spatial distribution of fracture and their reaction to stress. While those natural fractures which are intersected by the well are detectable on image logs, fractures in the vicinity of wellbore also need to be incorporated while studying the hydraulic conductivity at field scale. Detection of such fractures is possible with application of certain deep shear sonic technology. Well-scale geomechanical models offer reasonable accuracy to determine the sensitivity of detected fractures in respect to stress to become critically stressed and therefore possibly hydraulically conductive. However, the translation of such well-scale analyses to field-scale requires improvement in methodology. Appropriate up-scaling of well-based fracture interpretation to field-scale is already in practice in the form of DFN modeling based on the integration of field-scale data and well-based data. However, the effective integration of these models can offer solutions to identify possible stress sensitive fracture dominated sweetspots for improved well planning reservoir development. This presentation covers case studies.

Due to the success of slick water stimulation in shale plays such as the Barnett, this approach is increasingly being proposed for use in other plays. However, there has been little discussion of how to determine its appropriateness. We present here four cases in which such a workflow has been applied – these include a fractured basement tight light oil play, a fractured basement geothermal field, a mud rock gas play, and a tight gas sand. Shear stimulation was determined to be appropriate in two of these cases. In a third, insufficient benefit accrued. The fourth case demonstrates the importance of the work flow; had data been obtained prior to stimulation an alternative stimulation method might have been proposed. Required data include natural fracture orientations and distribution, and stress orientations and magnitudes. A pre-stimulation test is essential to determine fracture strengths, flow properties, and pre- and post-stimulation connectivity. Microseismic monitoring provides significant benefits in evaluating the results of these tests. Where shear stimulation is revealed not to provide sufficient enhancement of reservoir permeability to make a prospect viable, the choices are either to use a different stimulation method or to search for a more appropriate development location.

Stochastic approaches are often used to simulate discrete fracture networks that are consistent with statistics obtained from field observations. However, classical stochastic methods do not account for fracture interactions to draw the geometry and the position of fractures. In this work, the tectonic history is considered. The fractures related to the oldest tectonic events are simulated first and others are simulated by order until the youngest tectonic events is considered. We use geomechanical consideration to define both a repulsion zone (constraint release zone) and an attraction zone (constraint accumulation zone) around each fracture. The implantation and the growth of each fracture are optimized considering the effect of neighboring fracture already simulated. Simulated discrete fracture network may also be constrained by secondary data such as micro seismic events or connectivity data.

Although the relationship between reservoir formation permeability and fractures is complex, it is recognized that fractures play an important role in reservoir fluid flow. Recent research has been using the integrated geomechanics and seismic modelling to characterize tight-gas reservoirs, which requires knowledge of the joint or fracture compliances both on the geo-mechanic and seismic scale. However, populating the geomechanical and/or seismic model with joint and fracture properties is based primarily on laboratory core data, which are on many times smaller length scales than observed in fractured reservoirs. As such, it would be ideal to measure and calibrate fracture compliance from field-scale measurements. The aim of this project is to explore whether observations of seismic anisotropy from P- and S-waves can constrain fracture compliance (normal and shear). In this study, we investigate the feasibility of using microseismic data to invert for fracture density, fracture strike and fracture compliance ratio from shear splitting results.

Fractured reservoirs and their successful production my need to involve fracture shearing. This important mechanism may result in slight dilation of the fractures, and therefore substantial maintenance of conducting aperture, despite effective stress increase. Unless fractures are sealed with hard minerals, and channelized flow is occurring, closure would be likely with the standard geophysics model of one set of stress-parallel fractures. The minimum principal stress would close the fractures unless they were very rough and in hard rock, such as limestone. These scenarios suggest the need for fracture characterization, with a view to geomechanical coupled modeling, so that 4D reservoir monitoring results can be interpreted better than with continuum ‘stress and strain’ arguments, which have little relation to the detailed reality of continued fracture flow during production of petroleum.

Until recently direct imaging of reservoir scale fracture-flow networks has been impossible. High-resolution reflection seismic data provides images of larger fractures, but does not show which fractures are likely to be hydraulically transmissive. To date, reservoir-scale fracture networks have been characterized primarily by indirect methods such as: stochastic and/or deterministic mechanical modeling to upscale borehole data or downscale reflection seismic data; attributes derived from seismic reflection data; and well or reservoir tests that measure bulk flow properties. This presentation reports on a new passive seismic imaging method (Tomographic Fracture Imaging™) that directly images reservoir-scale fracture networks either during hydraulic fracture treatments, during production or injection, or using only ambient seismic emissions. Ambient imaging can be performed during the course of standard 3D reflection surveys by recording continuously during quiet periods, for example at night when there is no activity on the grid. The presentation will focus on well-documented case-studies where independent validation of the results is available. Case studies presented will include examples from hydraulic fracture treatments, ambient surveys, and a water flood. The results are validated with independent data including chemical and radioactive tracer studies, pressure monitoring, production logs, reflection seismic data, and well results.

The first part of this talk focuses on a short review on the major efforts made in the past few decades to understand fractures and fractured formations both in the industry (oil and gas, hydrogeology, nuclear waste management) and academic community. The second part of the talk focuses on a discussion of typical workflow for detection, characterization, parameterization, prediction, modeling, validation and verification of fractures from limited direct subsurface data, and how static and dynamic data can be integrated to get a more complete picture of the reservoir. The final part of the talk points out some general future research directions.