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Pore Typing a Tight Gas Sand Reservoir – The Mangahewa

April 19, 2018
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Presented by:  Scott Dodge, Virtual Petrophysics
DomainFormation Evaluation
TechnologyGeolog® 

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Abstract

Rock pore typing technology is developed for the tight gas sand Mangahewa reservoirs in the Taranaki basin to predict reservoir flow performance.  The technology of rock pore typing provides the means to accurately predict permeability and well producibility in these highly modified diagenetic sandstones that show no correlation of porosity and permeability.

Diagenesis adversely modifies the pore system, creating quartz cementation that reduces intergranular porosity as well as additional micro porosity associated with diagenetic clays and leached feldspar grains.  Thus, a complex pore system is created owing to mineral diagenesis accelerated by abnormal pressures and temperatures.

Characterization of the pore system is performed using laboratory MICP (Mercury Injection Capillary Pressure) and NMR (Nuclear Magnetic Resonance) on core plugs.  MICP measures the pore volume accessed by the non-wetting phase fluid, and NMR measures the surface-to-pore volume ratio, or pore sizes that are accessed by MICP.  The fundamental physics of capillary pressure measurements allow us to describe the pore system in terms of porosity, permeability, and non-wetting phase saturation as a function of effective pore radii.  Pore typing is accomplished without the need for lithology or mineralogy information to develop the permeability model.

This work shows that the laboratory NMR pore size distribution provides similar information to MICP and has been used in a Purcell-Ruth permeability model to quantify the distribution of reservoir permeability.  Additionally, discrete pore types identified are used to build a Petrophysical rock pore type catalog for this reservoir.  The pore type model is applied to the NMR wireline log to provide a continuous measure of pore types in wellbores.

This rock pore typing workflow is illustrated with the use of Geolog Formation Evaluation core analysis tools.


Biography

Scott-Dodge_sm.jpgScott Dodge is Director and Principal of Virtual Petrophysics, a Petrophysics technology company providing technical services to Oil and Gas operators in North America, Middle East and Australasia.

Previously he worked at ExxonMobil for more than 30 years as a Formation Evaluation Specialist, with experience in both clastic and carbonate reservoirs in North America, West Africa, Middle East, Europe, and Australasia.  His specializations include static and dynamic reservoir modelling, rock pore typing, NMR applications, special core analysis, cased-hole surveillance, and drill well programming and evaluation.

He holds a Bachelors of Science degree in Mechanical Engineering from Kansas State University, and a Masters of Science Degree in Petroleum Engineering from the University of Southern California.

Scott has served the SPWLA in various capacities as President of the Australia, Nigeria, and Malaysia chapters and Regional Director of Africa/Middle East, as well as Distinguished Lecturer from 1996 to 1998.  He is a member of EngNZ, GSNZ, SPE, SPWLA, SCA and AAPG.