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

David O. Egya, Sebastian Geiger, Patrick William Michael Corbett, Rafael March, Kevin Bisdom, Giovanni Bertotti, F. H. Bezerra

Research output: Contribution to journalArticle

Abstract

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.

LanguageEnglish
Pages30-49
Number of pages20
JournalPetroleum Geoscience
Volume25
Issue number1
Early online date17 Jan 2018
DOIs
Publication statusPublished - Feb 2019

Fingerprint

dual porosity
Porosity
well
fracture network
matrix
test
fracture geometry
well testing
Well testing
Hydrocarbons
fluid flow
Transient analysis
skin
outcrop
Flow of fluids
Skin
permeability
hydrocarbon

ASJC Scopus subject areas

  • Fuel Technology
  • Geology
  • Geochemistry and Petrology
  • Economic Geology
  • Earth and Planetary Sciences (miscellaneous)

Cite this

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abstract = "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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Analysing the limitations of the dual-porosity response during well-tests in naturally fractured reservoirs. / Egya, David O.; Geiger, Sebastian; Corbett, Patrick William Michael; March, Rafael; Bisdom, Kevin; Bertotti, Giovanni; Bezerra, F. H.

In: Petroleum Geoscience, Vol. 25, No. 1, 02.2019, p. 30-49.

Research output: Contribution to journalArticle

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AU - Geiger, Sebastian

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AU - March, Rafael

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AU - Bertotti, Giovanni

AU - Bezerra, F. H.

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