Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin

Jim Buckman, Obinna Chudi, Helen Lewis, Gary Couples, Tianshen Huang, Zeyun Jiang

Research output: Contribution to journalArticle

Abstract

Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36–51%, and the earlier Miocene samples have a porosity of around 18–35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234–1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.

Original languageEnglish
Article number106538
JournalJournal of Petroleum Science and Engineering
Volume184
Early online date30 Sep 2019
DOIs
Publication statusPublished - Jan 2020

Fingerprint

turbidite
Sandstone
cementation
Oligocene
Quartz
Porosity
porosity
Rocks
Miocene
sandstone
permeability
quartz
prediction
basin
rock
Cements
cement
software
Petroleum reservoirs
method

Keywords

  • Digital rock model
  • Permeability
  • Pore network model
  • Pore occlusion
  • Quartz cementation

ASJC Scopus subject areas

  • Fuel Technology
  • Geotechnical Engineering and Engineering Geology

Cite this

@article{b31a8c7daa304c42aebef023667e0f16,
title = "Synthetic digital rock methods to estimate the impact of quartz cementation on porosity & permeability: Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin",
abstract = "Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35{\%}. These reservoirs are typically poorly cemented, with less than 5{\%} quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36–51{\%}, and the earlier Miocene samples have a porosity of around 18–35{\%}. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234–1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20{\%}, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.",
keywords = "Digital rock model, Permeability, Pore network model, Pore occlusion, Quartz cementation",
author = "Jim Buckman and Obinna Chudi and Helen Lewis and Gary Couples and Tianshen Huang and Zeyun Jiang",
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T2 - Assessment of Miocene turbidite sandstones and prediction of deeper Oligocene sandstones, Niger Delta Basin

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AU - Chudi, Obinna

AU - Lewis, Helen

AU - Couples, Gary

AU - Huang, Tianshen

AU - Jiang, Zeyun

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N2 - Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36–51%, and the earlier Miocene samples have a porosity of around 18–35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234–1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.

AB - Deep-water Miocene sandstones from the Niger Delta Basin form economically significant petroleum reservoirs, with porosity commonly up to 35%. These reservoirs are typically poorly cemented, with less than 5% quartz cement. Thin-section-based digital-rock models (DRM) based on backscattered electron (BSE) scanning electron microscopy (SEM) images, using lightly-cemented rock cuttings recovered during drilling, and their derived three-dimensional pore network models (PNM's) of Miocene reservoir sands (within the Agbada Formation), are used to assess pore-system architecture, porosity and permeability. This was accomplished by the digital addition of quartz cement to the DRM's, using image analysis software, with altered models then analysed for changes in porosity and permeability using PNM software. Samples exhibit different values of porosity, in part reflecting their vertical position within the sequence. Later Miocene samples from the current study are characterized by initial porosity of around 36–51%, and the earlier Miocene samples have a porosity of around 18–35%. DRM derived Permeability for the later Miocene samples ranges from approximately 5 to 30 D, with values in the region of 234–1618 mD for deeper early Miocene material. Wireline logs of Oligocene sandstones from nearby locations suggest that they are likely to be more heavily cemented. The digital-rock models provide the basis for forward-modelled porosity-permeability changes (to <20%, 100-180 mD) that could characterise the undrilled but likely similar Oligocene reservoir sandstones. The later Miocene samples (8102, 8115, 8134 ft depth) are lightly cemented and do not display a high-degree of compaction, but rather show a very open pore structure and high permeability. They are unlikely to represent good analogues as their forward-modelled cementation effects do not conform to the predicted Oligocene sandstone physical parameters, but earlier Miocene samples (8382, 11,486 ft depth) display a more normal pore network structure, lower porosity and are better analogues for forward modelling of an Oligocene reservoir.

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