Discriminating Fracture Patterns in Fractured Reservoirs by Pressure Transient Tests

Wei, Lingli; Hadwin, Jerry; Chaput, Eric; Rawnsley, Keith; Peter, Swaby

doi:10.2523/49233-ms

Cited by 9 publications

(10 citation statements)

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“…Therefore, by using the local discrete fracture model, it is possible to invert these parameters from these dynamic data. Computation procedures are already available (Wei et al 1998;Garcia & Sarda 1999), but the practical method to use them on a case study is not yet established; it is one of our next challenges.…”

Section: Discussionmentioning

confidence: 99%

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Nested geological modelling of naturally fractured reservoirs

2001

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Because of the multiscaled character of fracture networks and their high degree of heterogeneity, characterization and modelling of fractured reservoirs requires different techniques to the well-established geostatistical methods derived for modelling rock heterogeneity. We have developed a method to improve the geological model used as an input of fractured reservoir fluid flow simulators, either in single or dual permeability simulations, as well as new specific procedures. The method is based on three nested models. The first, the 'global geo-cellular fracture model', considers fracture average property distribution at the scale of the reservoir. Location of the major faults as well as properties, such as horizon curvature, are taken into account. 'The global discrete model' considers the fault system at the same scale and algorithms generate realistic synthetic fault patterns using an object-orientated approach. The third model, the 'local discrete model', creates realistic synthetic fracture patterns at the decametre scale with another objectorientated procedure. These models are all constrained by hard data acquired from seismic, well imaging and logs. They can be constrained by output from deterministic approaches like structural evolution analyses and geomechanical modelling. Interrelationships between these models enable account to be taken of the complex interrelationships between fractures at different scales and rock material heterogeneity. Finally, this modelling approach makes the geological model used as an input of fractured reservoir fluid flow simulators more satisfying than conventional approaches.

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Section: Discussionmentioning

confidence: 99%

“…Fracture size distributions are usually estimated from outcrop analyses. Core and borehole data can provide relative values of fracture aperture (Luthi & Souhaité 1990), but the best aperture estimates are obtained by a calibration procedure based on well test simulation (Cacas 1989;Wei et al 1998).…”

Section: The Local Discrete Model (Small-scale Fractures)mentioning

confidence: 99%

Nested geological modelling of naturally fractured reservoirs

2001

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“…It has been shown (Bourdet et al , 1989 that the derivative of pressure (dp/dlogt) is more sensitive than the change of pressure itself to the properties of the reservoir. Indeed several authors (Ayoub et al 1983;O'Sullivan 1987, Wei et al 1998Wei 2000;Casciano et al 2004) have shown that the shape of the pressure derivative is sensitive to the properties of the fracture network through which diffusion is occurring. Different representations of the pressure disturbance geometry can be distinguished from the slope of the pressure derivative (Barker 1988), as can the time at which different boundaries are reached by the pressure disturbance.…”

Section: F L O W In the Fracture Networkmentioning

confidence: 99%

“…The way in which pressure changes with time is known to be a function of the properties of the formation (Home 1995) and these data can also be used to infer properties of fracture networks. Although no unique solution exists for such inverse problems, it may be possible to discriminate between different equally plausible models (Wei et al 1998;Casciano et al 2004). Fracture networks are not random systems; they form in response to stresses in the brittle crust and depend on interactions with pre-existing structures.…”

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Study of fracture-induced anisotropy from discrete fracture network simulation of well test responses

Leckenby

Lonergan

Rogers

et al. 2007

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Different conceptualizations of fracture networks have been generated in order to simulate well tests in fractured reservoirs. These models have two purposes: firstly to investigate whether the behaviour of realistic fracture networks can be emulated with more simple models; and secondly to assess whether different sources of anisotropy have characteristic and recognizable influences on the pressure derivative. The anisotropy of the fracture networks was increased by decreasing the angle between two originally orthogonal fracture sets, and by increasing the permeability contrast between two orthogonal fracture sets. Results indicate that simple models can capture the first-order behaviour of more realistic examples. However because early time data are strongly influenced by the connectivity of the fracture network, the degree of anisotropy can only be assessed at later times in a test. Increasing anisotropy results in increasing heterogeneity and compartmentalization, and permeability anisotropy in an orthogonal system can only partially replicate the behaviour of a geometrically anisotropic system.

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Analysing the limitations of the dual-porosity response during well tests in naturally fractured reservoirs

Egya

Geiger

Corbett

et al. 2018

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Geological reservoirs can be extensively fractured but the well-test signatures observed in the wells may not show a pressure transient response that is representative of naturally fractured reservoirs (NFRs): for example, one that indicates two distinct pore systems (i.e. the mobile fractures and immobile matrix). Yet, the production behaviour may still be influenced by these fractures. To improve the exploitation of hydrocarbons from NFRs, we therefore need to improve our understanding of fluid-flow behaviour in fractures. Multiple techniques are used to detect the presence and extent of fractures in a reservoir. Of particular interest to this work is the analysis of well-test data in order to interpret the flow behaviour in an NFR. An important concept for interpreting well-test data from an NFR is the theory of dual-porosity model. However, several studies pointed out that the dual-porosity model may not be appropriate for interpreting well tests from all fractured reservoirs. This paper therefore uses geological well-testing insights to explore the limitations of the characteristic flow behaviour inherent to the dual-porosity model in interpreting well-test data from Type II and III NFRs of Nelson's classification. To achieve this, we apply a geoengineering workflow with discrete fracture matrix (DFM) modelling techniques and unstructured-grid reservoir simulations to generate synthetic pressure transient data in both idealized fracture geometries and real fracture networks mapped in an outcrop of the Jandaira Formation. We also present key reservoir features that account for the classic V-shape pressure derivative response in NFRs. These include effects of fracture skin, a very tight matrix permeability and wells intersecting a minor, unconnected fracture close to a large fracture or fracture network. Our findings apply to both connected and disconnected fracture networks.

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Discriminating Fracture Patterns in Fractured Reservoirs by Pressure Transient Tests

Cited by 9 publications

References 0 publications

Nested geological modelling of naturally fractured reservoirs

Nested geological modelling of naturally fractured reservoirs

Study of fracture-induced anisotropy from discrete fracture network simulation of well test responses

Analysing the limitations of the dual-porosity response during well tests in naturally fractured reservoirs

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