Imaging the Microstructure of Reservoir Rocks in 3D and 4D

Friday, 15 June 2018 — Copenhagen, Denmark

Visit our Booth #1818


80th EAGE Conference & Exhibition 2018
European Association of Geoscientists and Engineers
Opportunities presented by the energy transition

Workshop Programme

09:00

Welcome 

 

09:10

Predicting Properties of Fine Grained Reservoir Rocks by Ultra-high Resolution X-ray Imaging

S.Bruns (Univ. of Copenhagen)

09:40

Time-resolved Three-dimensional Imaging of Multiphase Flow in Permeable Media

K. Singh (Imperial College London)

10:20

Multiphase Flow Near Charged Walls

J. Mathiesen (Univ. of Copenhagen)

11:00

Coffee break 

 

11:20

Using Nano-CT and High-contrast Imaging to Inform Microporosity Permeability during Stokes-Brinkman Flow Simulations

H.Menke (Imperial College London)

12:00

Flow and Reactive Transport at the Microscopic Scale - Derivation of porous media transport properties

A.Raoof (Utrecht Univ.)

12:40 

Lunch break 

 

13:30

Poster session & Discussions - Coffee break 

 

15:00

Screening of EOR Potential onthe Pore Scale - Application of Microfluidics to Alkaline Flooding

H.Ott (Montanuniversität Leoben)

15:40

Organic Hosted and Intergranular Pore Networks - Topography andtopology in grains, gaps & bubbles see abstract below

M.Andrew (C. Zeiss)

16:20

Conclusions

 

16:50

End of Workshop

 

Abstract
Organic hosted and intergranular pore networks: Topography and Topology in Grains, Gaps &. Bubbles

The advent of shale production has transformed the energy industry, however to date a generic understanding of pore structures within these unconventional systems has been lacking, which, in turn, has limited and understanding of recovery mechanisms within these reservoirs, leaving total reservoir recovery extremely low. In this study we compare and contrast two qualitatively different pore systems. Organic hosted porosity (existing on the nanometer scale and common in unconventional shale reservoirs) was imaged using 3D FIB-SEM techniques, and intergranular porosity (common in conventional sandstone reservoirs and existing on the micrometer scale) was imaged using micro-CT techniques. Scale independent connectivity metrics found the intergranular pore network to be much better connected than the organic hosted pore network, despite similar total porosity. This contrast is explained by strong variations in pore shape (as measured by sphericity and pore network curvature) which are in turn explained by variations in the geological processes responsible for the genesis of the pore network. The impact of such changes in pore shape on pore network connectivity was examined by creating a suite synthetic pore geometries using both erosion / dilation of the existing network and image guided object based methods, showing strong statistical agreement between the imaged and synthetic pore networks. These synthetic pore networks were then used to examine how connectivity changes as a function of porosity (as may arise by varying degrees of shale maturity, or by reservoir diagenesis), showing that network connectivity, needed for effective capillary imbibition, is much easier to achieve in organic-type pore networks than in the intergranular-type pore networks. We then review how such techniques might be applied to solve problems within the petroleum industry, including the development of new pore-scale core analysis techniques to access fundamental petrophysical parameters and the application of wellsite imaging to aid completion spacing and geosteering.

The advent of shale production has transformed the energy industry, however to date a generic pore scale recovery mechanisms (governed by pore network structure) has been lacking. Two qualitatively different pore systems were compared and contrasted using scale independent techniques, finding organic hosted porosity (nanometer scale and common in unconventional reservoirs) to be much better connected than intergranular porosity (micrometer scale and common in conventional reservoirs). This contrast is explained by variations in pore shape, caused in turn by variations in the geological processes responsible for pore network genesis. These processes were examined by creating a suite synthetic pore geometries with strong statistical agreement between imaged and synthetic pore networks. Synthetic pore networks were then used to examine how connectivity changes with porosity (as may arise by varying degrees of shale maturity, or by reservoir diagenesis), showing that network connectivity, needed for effective capillary imbibition, is much easier to achieve in organic-type pore networks than in the intergranular-type pore networks. We then review how such techniques might be applied to solve problems within the petroleum industry, including the development of new pore-scale core analysis techniques and the application of wellsite imaging to aid production operations.

Large area electron microscopy map, classified using a machine learning algorithm, showing organic hosted pore structures (red), silicate mineral phases (green), pyrite (yellow) and microfractures (blue)

Bio

Dr. Matthew Andrew currently directs development of high resolution imaging technologies for the Oil and Gas Industry and the Geosciences within ZEISS microscopy. He completed his PhD at Imperial College London, where he developed the first pore scale core analysis system capable of imaging multiple fluid phases at reservoir conditions, which he used to examine a range of petrophysical properties including wettability, capillary pressure, flow dynamics and trapping behavior. His current research interests include the use of multiscale experimental methods for the investigation of multiphase flow, the integration of multimodal high resolution analysis with modern data science tools, the application of automated high resolution imaging technology to petroleum operations problems and the integration of data science techniques with petroleum production.

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