Defining Net Pay Cutoffs in Carbonates Using Advanced Petrophysical Methods
- Mark Skalinski (Chevron) | Robert Mallan (Chevron) | Mason Edwards (Chevron) | Boqin Sun (Chevron) | Emmanuel Toumelin (Chevron) | Grant Kelly (Chevron) | Hazaretali Wushur (Chevron) | Michael Sullivan (Chevron)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- SPWLA 59th Annual Logging Symposium, 2-6 June, London, UK
- Publication Date
- Document Type
- Conference Paper
- 2018. held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors.
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Assessment of net pay cutoffs in carbonates is more challenging than in clastics due to inherent heterogeneity of pore architecture and permeability. Historically, the success rate of flowing perforations is low, and operators tend to “over-perforate” to capture all potential flowing zones. Asset teams must assign net thicknesses for modeling and resources assessment. Simple porosity cutoffs which might be adequate for sandstones often fail in complex carbonates. This study was undertaken to assess definitions of cutoffs in carbonates, leveraging applications of NMR logging, capillary pressure, and in-situ flow measurements.
First, we looked at the cutoffs defining hydrocarbon charge into the pore system. Proper determination of this cutoff can help better estimate hydrocarbon in place. To address this question, we have developed NMR T2 Shape and 2D Shape analyses to define the minimum porosity and/or permeability with detectable hydrocarbon signal. The T2 shape analyses were performed for several carbonate fields around the world, yielding porosity cutoff for hydrocarbon charge varying between 1.5 and 3.5%, depending on reservoir type.
Second, extensive MICP data from these carbonate fields were used to predict an entry pore throat radius corresponding to potential hydrocarbon charge. The predicted entry pore throat log combined with the pore throat size corresponding to capillary pressure at specific height above free water level (HAFWL) allowed to define zones which were not penetrated by hydrocarbon charge due insufficient capillary pressure. Definition of those zones collaborated very well with results from the NMR Shape analysis, extending our ability to define “gross hydrocarbon” for fields without NMR data.
The next cutoff investigated was the minimum value of permeability that correlated with observed flow of in-situ fluids, i.e.: production logs, derivative of temperature logs, and wireline pressure tests. This cutoff would correspond to the conventional “net reservoir” definition. The use of permeability mitigates the need for porosity cutoffs which usually varies by rock types. We have predicted permeability from logs using the K-Nearest Neighbor method which reconstructs well the core permeability distribution. The study performed in the different carbonate reservoirs yielded permeability cutoffs varying between 0.01and 0.1 mD.
This approach allowed us to define a set of recommendations for definitions of net reservoir and net pay, and to provide a practical methodology to assess hydrocarbon potential. The methods presented here can be applied to any conventional reservoirs.
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