Seismic Attributes to Constrain the Distribution of Rakopi Formation Coals in the Southwest Offshore Taranaki Basin, New Zealand

<p>The Rakopi Formation, in the Taranaki Basin of New Zealand, is a Late Cretaceous (Haumurian) sequence of coal measures interbedded with siltstone and sparse sandstone. It is the lowest widespread stratigraphic unit in the Taranaki Basin, and has a syn-rift deposition which is concentrated in isolated grabens and sub-basins. It was deposited during the extensional tectonic regime linked to the breakup of Gondwana. The Rakopi is one of the major hydrocarbon source rocks in the Taranaki Basin; New Zealand’s only currently-producing basin. However, there are very few well penetrations of the Cretaceous interval within the basin, and this fact – coupled with the non-continuous deposition – means that the Rakopi’s distribution is poorly constrained further away from wells. In petroleum systems models, the entire Rakopi Formation interval is commonly represented entirely as source rock facies. By observing the limited well penetrations available, it is known that this is not the case. As such, it is likely that the total hydrocarbons generated within the basin are overestimated when modelled. Improved constraint of the distribution of the coal within the Rakopi Formation will improve the accuracy of these models. This study presents the results of the extraction and analysis of a suite of seismic attributes from 3D seismic reflection surveys in the southwest offshore Taranaki Basin, for the purpose of constraining the distribution of coal within the Rakopi Formation. The attribute outputs were temporally averaged, with the resulting frequency distributions analysed for significant patterns or variations between the coaly- versus non-coaly vertical intervals of the formation. Within the Maari 3D seismic reflection volume, six attributes were identified which correlated with the presence of coals observed in the Maui-4 well. These attributes were temporally averaged within the Rakopi Formation interval in both the Maari 3D and Pipeline 3D volumes, with the areas of high average values identified as being more likely to contain coal. Using this attribute analysis method, the distribution of coal within the Rakopi Formation has been better constrained. Attribute analysis is easily transferable, and has the potential to be utilised elsewhere for the identification of hydrocarbon source rocks.</p>

Seismic Attributes to Constrain the Distribution of Rakopi Formation Coals in the Southwest Offshore Taranaki Basin, New Zealand

<p>The Rakopi Formation, in the Taranaki Basin of New Zealand, is a Late Cretaceous (Haumurian) sequence of coal measures interbedded with siltstone and sparse sandstone. It is the lowest widespread stratigraphic unit in the Taranaki Basin, and has a syn-rift deposition which is concentrated in isolated grabens and sub-basins. It was deposited during the extensional tectonic regime linked to the breakup of Gondwana. The Rakopi is one of the major hydrocarbon source rocks in the Taranaki Basin; New Zealand’s only currently-producing basin. However, there are very few well penetrations of the Cretaceous interval within the basin, and this fact – coupled with the non-continuous deposition – means that the Rakopi’s distribution is poorly constrained further away from wells. In petroleum systems models, the entire Rakopi Formation interval is commonly represented entirely as source rock facies. By observing the limited well penetrations available, it is known that this is not the case. As such, it is likely that the total hydrocarbons generated within the basin are overestimated when modelled. Improved constraint of the distribution of the coal within the Rakopi Formation will improve the accuracy of these models. This study presents the results of the extraction and analysis of a suite of seismic attributes from 3D seismic reflection surveys in the southwest offshore Taranaki Basin, for the purpose of constraining the distribution of coal within the Rakopi Formation. The attribute outputs were temporally averaged, with the resulting frequency distributions analysed for significant patterns or variations between the coaly- versus non-coaly vertical intervals of the formation. Within the Maari 3D seismic reflection volume, six attributes were identified which correlated with the presence of coals observed in the Maui-4 well. These attributes were temporally averaged within the Rakopi Formation interval in both the Maari 3D and Pipeline 3D volumes, with the areas of high average values identified as being more likely to contain coal. Using this attribute analysis method, the distribution of coal within the Rakopi Formation has been better constrained. Attribute analysis is easily transferable, and has the potential to be utilised elsewhere for the identification of hydrocarbon source rocks.</p>

Phenomenological models for estimating and constraining c13 for transversely isotropic hydrocarbon source rocks

Hydrocarbon source rocks can be adequately approximated as transversely isotropic (TI) media. The elastic properties of a TI medium are defined by five stiffness parameters: c11, c33, c44, c66, and c13. The laboratory estimation of c11, c33, c44, and c66 is straightforward, with each of the stiffness parameters determined by a single velocity measurement in an orthogonal direction. For c13, we need the information of c11, c33, c44, and at least one oblique velocity. Consequently, it is usually more difficult to estimate c13 than the other stiffness parameters in the laboratory, and it is even more challenging to acquire it from the field. Therefore, it is important to find the relations between c13 and the other stiffness parameters so that c13 can be estimated from the orthogonal elastic tensor elements c11, c33, c44, and c66 that can be much more economically and reliably acquired. There are phenomenological models for estimating c13 from the other stiffness parameters, but their accuracy is not always satisfactory. We found that c13 has strong correlations with c33 − 2 c44 and c11 − 2 c66, and that c33 − 2 c44 generally underestimates c13 and c11 − 2 c66 generally overestimates c13. The average of c33 − 2 c44 and c11 − 2 c66 can be a much more precise phenomenological model to approximate c13. We also found that c11 − 2 c66 is generally greater than c33 − 2 c44 for hydrocarbon source rocks. Therefore, we evaluated that c13 should lie between c33 − 2 c44 and c11 − 2 c66 for hydrocarbon source rocks.